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Indiana Michigan Power

Filed: 25 Feb 21, 8:27am
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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C.  20549
 
FORM 10-K
 
(Mark One)

ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2020
or
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from __________ to_________
Commission Registrants; I.R.S. Employer
File Number Address and Telephone Number States of Incorporation Identification Nos.
     
1-3525 AMERICAN ELECTRIC POWER CO INC.New York 13-4922640
333-221643AEP TEXAS INC.Delaware51-0007707
333-217143 AEP TRANSMISSION COMPANY, LLCDelaware 46-1125168
1-3457 APPALACHIAN POWER COMPANYVirginia 54-0124790
1-3570 INDIANA MICHIGAN POWER COMPANYIndiana 35-0410455
1-6543 OHIO POWER COMPANYOhio 31-4271000
0-343 PUBLIC SERVICE COMPANY OF OKLAHOMAOklahoma 73-0410895
1-3146 SOUTHWESTERN ELECTRIC POWER COMPANYDelaware 72-0323455
  1 Riverside Plaza,Columbus,Ohio43215-2373  
  Telephone(614)716-1000  

Securities registered pursuant to Section 12(b) of the Act:
Registrant Title of each class Trading SymbolName of Each Exchange on Which Registered
American Electric Power Company Inc.Common Stock, $6.50 par valueAEPThe NASDAQ Stock Market LLC
American Electric Power Company Inc.6.125% Corporate UnitsAEPPLThe NASDAQ Stock Market LLC
American Electric Power Company Inc.6.125% Corporate UnitsAEPPZThe NASDAQ Stock Market LLC



Securities registered pursuant to Section 12(g) of the Act:  None
Indicate by check mark if the registrant American Electric Power Company, Inc., AEP Texas Inc., AEP Transmission Company, LLC, Ohio Power Company and Southwestern Electric Power Company, are well-known seasoned issuers, as defined in Rule 405 of the Securities Act.YesxNo¨
Indicate by check mark if the registrants Appalachian Power Company, Indiana Michigan Power Company and Public Service Company of Oklahoma, are well-known seasoned issuers, as defined in Rule 405 of the Securities Act.Yes¨Nox
Indicate by check mark if the registrants are not required to file reports pursuant to Section 13 or Section 15(d) of the Exchange Act.Yes¨Nox
Indicate by check mark whether the registrants (1) have filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrants were required to file such reports), and (2) have been subject to such filing requirements for the past 90 days.YesxNo¨
Indicate by check mark whether the registrants have submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).YesxNo¨
Indicate by check mark whether American Electric Power Company, Inc. is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company.  See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
 
Large Accelerated filerxAccelerated filerNon-accelerated filer
      
Smaller reporting companyEmerging growth company
Indicate by check mark whether AEP Texas Inc., AEP Transmission Company, LLC, Appalachian Power Company, Indiana Michigan Power Company, Ohio Power Company, Public Service Company of Oklahoma and Southwestern Electric Power Company are large accelerated filers, accelerated filers, non-accelerated filers, smaller reporting companies, or emerging growth companies.  See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
 
Large Accelerated filerAccelerated filerNon-accelerated filerx
      
Smaller reporting companyEmerging growth company 
If an emerging growth company, indicate by check mark if the registrants have elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.
Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report.
Indicate by check mark whether the registrants are shell companies (as defined in Rule 12b-2 of the Exchange Act).YesNox

AEP Texas Inc., AEP Transmission Company, LLC, Appalachian Power Company, Indiana Michigan Power Company, Ohio Power Company, Public Service Company of Oklahoma and Southwestern Electric Power Company meet the conditions set forth in General Instruction I(1)(a) and (b) of Form 10-K and are therefore filing this Form 10-K with the reduced disclosure format specified in General Instruction I(2) to such Form 10-K.



 Aggregate Market Value of Voting and Non-Voting Common Equity Held by Nonaffiliates of the Registrants as of June 30, 2020 the Last Trading Date of the Registrants' Most Recently Completed Second Fiscal QuarterNumber of Shares of Common Stock Outstanding of the Registrants as of December 31, 2020
American Electric Power Company, Inc.$39,549,558,010496,604,194 
  ($6.50 par value)
AEP Texas Inc.None100 
($0.01 par value)
AEP Transmission Company, LLC (a)NoneNA
Appalachian Power CompanyNone13,499,500 
  (no par value)
Indiana Michigan Power CompanyNone1,400,000 
  (no par value)
Ohio Power CompanyNone27,952,473 
  (no par value)
Public Service Company of OklahomaNone9,013,000 
  ($15 par value)
Southwestern Electric Power CompanyNone3,680 
  ($18 par value)
(a)100% interest is held by AEP Transmission Holdco.
NA    Not applicable.

Note on Market Value of Common Equity Held by Nonaffiliates

American Electric Power Company, Inc. owns all of the common stock of AEP Texas Inc., Appalachian Power Company, Indiana Michigan Power Company, Ohio Power Company, Public Service Company of Oklahoma and Southwestern Electric Power Company and, indirectly, all of the LLC membership interest in AEP Transmission Company, LLC (see Item 12 herein).




Documents Incorporated By Reference
Description Part of Form 10-K into which Document is Incorporated
   
Portions of Annual Reports of the following companies for the fiscal year ended December 31, 2020: Part II
American Electric Power Company, Inc.  
AEP Texas Inc.
AEP Transmission Company, LLC
Appalachian Power Company  
Indiana Michigan Power Company  
Ohio Power Company  
Public Service Company of Oklahoma  
Southwestern Electric Power Company  
   
Portions of Proxy Statement of American Electric Power Company, Inc. for 2021 Annual Meeting of Shareholders. Part III

This combined Form 10-K is separately filed by American Electric Power Company, Inc., AEP Texas Inc., AEP Transmission Company, LLC, Appalachian Power Company, Indiana Michigan Power Company, Ohio Power Company, Public Service Company of Oklahoma and Southwestern Electric Power Company.  Information contained herein relating to any individual registrant is filed by such registrant on its own behalf.  Except for American Electric Power Company, Inc., each registrant makes no representation as to information relating to the other registrants.

You can access financial and other information at AEP’s website, including AEP’s Principles of Business Conduct, certain committee charters and Principles of Corporate Governance.  The address is www.AEP.com.  Investors can obtain copies of our SEC filings from this site free of charge, as well as from the SEC website at www.sec.gov.




TABLE OF CONTENTS
Item
Number
 Page
Number
 Glossary of Terms
 Forward-Looking Information
PART I
1Business 
 General
 Business Segments
 Vertically Integrated Utilities
 Transmission and Distribution Utilities
 AEP Transmission Holdco
 Generation & Marketing
 Executive Officers of AEP
1ARisk Factors
1BUnresolved Staff Comments
2Properties
 Generation Facilities
 
 Title to Property
 
 Construction Program
 Potential Uninsured Losses
3Legal Proceedings
4Mine Safety Disclosure
PART II
5Market for Registrants’ Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
6Reserved
7Management’s Discussion and Analysis of Financial Condition and Results of Operations
7AQuantitative and Qualitative Disclosures about Market Risk
8Financial Statements and Supplementary Data
9
Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
9AControls and Procedures
9BOther Information
PART III
10Directors, Executive Officers and Corporate Governance
11Executive Compensation
12Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
13
14Principal Accounting Fees and Services
PART IV
15Exhibits and Financial Statement Schedules
 Financial Statements
Form 10-K Summary
 Signatures
 Index of Financial Statement Schedules
S-1
 Report of Independent Registered Public Accounting Firm
S-2
 Exhibit Index
E-1



GLOSSARY OF TERMS

When the following terms and abbreviations appear in the text of this report, they have the meanings indicated below.
Term Meaning
   
AEGCo AEP Generating Company, an AEP electric utility subsidiary.
AEP American Electric Power Company, Inc., an investor-owned electric public utility holding company which includes American Electric Power Company, Inc. (Parent) and majority-owned consolidated subsidiaries and consolidated affiliates.
AEP CreditAEP Credit, Inc., a consolidated VIE of AEP which securitizes accounts receivable and accrued utility revenues for affiliated electric utility companies.
AEP East CompaniesAPCo, I&M, KGPCo, KPCo, OPCo and WPCo.
AEP EnergyAEP Energy, Inc., a wholly-owned retail electric supplier for customers in Ohio, Illinois and other deregulated electricity markets throughout the United States.
AEP Energy Supply, LLCA nonregulated holding company for AEP’s competitive generation, wholesale and retail businesses, and a wholly-owned subsidiary of AEP.
AEP OnSite PartnersA division of AEP Energy Supply, LLC that builds, owns, operates and maintains customer solutions utilizing existing and emerging distributed technologies.
AEP RenewablesA division of AEP Energy Supply, LLC that develops and/or acquires large scale renewable projects that are backed with long-term contracts with creditworthy counter parties.
AEP System American Electric Power System, an electric system, owned and operated by AEP subsidiaries.
AEP TexasAEP Texas Inc., an AEP electric utility subsidiary.
AEP Transmission HoldcoAEP Transmission Holding Company, LLC, a wholly-owned subsidiary of AEP.
AEP UtilitiesAEP Utilities, Inc., a former subsidiary of AEP and holding company for TCC, TNC and CSW Energy, Inc.  Effective December 31, 2016, TCC and TNC were merged into AEP Utilities, Inc.  Subsequently following this merger, the assets and liabilities of CSW Energy, Inc. were transferred to a competitive affiliate company and AEP Utilities, Inc. was renamed AEP Texas Inc.
AEP Wind Holdings LLCAcquired in April 2019 as Sempra Renewables LLC, develops, owns and operates, or holds interests in, wind generation facilities in the United States.
AEPEPAEP Energy Partners, Inc., a subsidiary of AEP dedicated to wholesale marketing and trading, hedging activities, asset management and commercial and industrial sales in deregulated markets.
AEPROAEP River Operations, LLC, a commercial barge operation sold in November 2015.
AEPSC American Electric Power Service Corporation, an AEP service subsidiary providing management and professional services to AEP and its subsidiaries.
AEPTCo AEP Transmission Company, LLC, a wholly-owned subsidiary of AEP Transmission Holdco, is an intermediate holding company that owns the State Transcos.
AEPTCo ParentAEP Transmission Company, LLC, the holding company of the State Transcos within the AEPTCo consolidation.
AEPTHCo AEP Transmission Holding Company, LLC, a subsidiary of AEP, an intermediate holding company that owns transmission operations joint ventures and AEPTCo.
AFUDC Allowance for Equity Funds Used During Construction.
AGR AEP Generation Resources Inc., a competitive AEP subsidiary in the Generation & Marketing segment.
ALJAdministrative Law Judge.
AMIAdvanced Metering Infrastructure.
AMTAlternative Minimum Tax.
AOCIAccumulated Other Comprehensive Income.
APCo Appalachian Power Company, an AEP electric utility subsidiary.
i


Term Meaning
   
Appalachian Consumer Rate Relief FundingAppalachian Consumer Rate Relief Funding LLC, a wholly-owned subsidiary of APCo and a consolidated VIE formed for the purpose of issuing and servicing securitization bonds related to the under-recovered ENEC deferral balance.
APTCoAEP Appalachian Transmission Company, Inc., a wholly-owned AEPTCo transmission subsidiary.
APSCArkansas Public Service Commission.
ARAMAverage Rate Assumption Method, an IRS approved method used to calculate the reversal of Excess ADIT for rate-making purposes.
AROAsset Retirement Obligations.
ASUAccounting Standards Update.
CAA Clean Air Act.
CAA of 2021Consolidated Appropriations Act of 2021 signed into law in December 2020.
Cardinal Operating CompanyA jointly-owned organization between AGR and a nonaffiliate. The nonaffiliate operates the three unit Cardinal Plant and wholly-owns Units 2 and 3.
CARES ActCoronavirus Aid, Relief, and Economic Security Act signed into law in March 2020.
CLECOCentral Louisiana Electric Company, a nonaffiliated utility company.
CO2
 Carbon dioxide and other greenhouse gases.
Conesville PlantA retired, single unit coal-fired generation plant totaling 651 MW located in Conesville, Ohio. The plant was jointly-owned by AGR and a nonaffiliate.
Cook Plant Donald C. Cook Nuclear Plant, a two-unit, 2,288 MW nuclear plant owned by I&M.
COVID-19Coronavirus 2019, a highly infectious respiratory disease. In March 2020, the World Health Organization declared COVID-19 a worldwide pandemic.
CRES providerCompetitive Retail Electric Service providers under Ohio law that target retail customers by offering alternative generation service.
CSAPRCross-State Air Pollution Rule.
CSPCo Columbus Southern Power Company, a former AEP electric utility subsidiary that was merged into OPCo effective December 31, 2011.
CWAClean Water Act.
CWIPConstruction Work in Progress.
DCC FuelDCC Fuel IX, DCC Fuel X, DCC Fuel XI, DCC Fuel XII, DCC Fuel XIII, DCC Fuel XIV and DCC Fuel XV, consolidated VIEs formed for the purpose of acquiring, owning and leasing nuclear fuel to I&M.
Desert SkyDesert Sky Wind Farm LLC, a 170 MW wind electricity generation facility located on Indian Mesa in Pecos County, Texas in which AEP owns a 100% interest.
DHLCDolet Hills Lignite Company, LLC, a wholly-owned lignite mining subsidiary of SWEPCo.
DIRDistribution Investment Rider.
DOEU. S. Department of Energy.
EISEnergy Insurance Services, Inc., a nonaffiliated captive insurance company and consolidated VIE of AEP.
ENECExpanded Net Energy Cost.
Energy SupplyAEP Energy Supply LLC, a nonregulated holding company for AEP’s competitive generation, wholesale and retail businesses, and a wholly-owned subsidiary of AEP.
Equity UnitsAEP’s Equity Units issued in August 2020 and March 2019.
ERCOT Electric Reliability Council of Texas regional transmission organization.
ESPElectric Security Plans, a PUCO requirement for electric utilities to adjust their rates by filing with the PUCO.
ETT Electric Transmission Texas, LLC, an equity interest joint venture between AEP Transmission Holdco and Berkshire Hathaway Energy Company formed to own and operate electric transmission facilities in ERCOT.
Excess ADITExcess accumulated deferred income taxes.
FACFuel Adjustment Clause.
ii


Term Meaning
   
FASBFinancial Accounting Standards Board.
Federal EPA United States Environmental Protection Agency.
FERC Federal Energy Regulatory Commission.
FGDFlue Gas Desulfurization or scrubbers.
FIPFederal Implementation Plan.
FTRFinancial Transmission Right, a financial instrument that entitles the holder to receive compensation for certain congestion-related transmission charges that arise when the power grid is congested resulting in differences in locational prices.
GAAPAccounting Principles Generally Accepted in the United States of America.
Global SettlementIn February 2017, the PUCO approved a settlement agreement filed by OPCo in December 2016 which resolved all remaining open issues on remand from the Supreme Court of Ohio in OPCo’s 2009 - 2011 and June 2012 - May 2015 ESP filings. It also resolved all open issues in OPCo’s 2009, 2014 and 2015 SEET filings and 2009, 2012 and 2013 FAC Audits.
I&M Indiana Michigan Power Company, an AEP electric utility subsidiary.
IMTCoAEP Indiana Michigan Transmission Company, Inc., a wholly-owned AEPTCo transmission subsidiary.
IRSInternal Revenue Service.
ITCInvestment Tax Credit.
IURC Indiana Utility Regulatory Commission.
KGPCo Kingsport Power Company, an AEP electric utility subsidiary.
KPCo Kentucky Power Company, an AEP electric utility subsidiary.
KPSCKentucky Public Service Commission.
KTCoAEP Kentucky Transmission Company, Inc., a wholly-owned AEPTCo transmission subsidiary.
kVKilovolt.
KWhKilowatt-hour.
LPSCLouisiana Public Service Commission.
MATSMercury and Air Toxic Standards.
MISO Midcontinent Independent System Operator.
MMBtu Million British Thermal Units.
MPSCMichigan Public Service Commission.
MTMMark-to-Market.
MW Megawatt.
MWhMegawatt-hour.
NAAQSNational Ambient Air Quality Standards.
NERCNorth American Electric Reliability Corporation.
Nonutility Money Pool Centralized funding mechanism AEP uses to meet the short-term cash requirements of certain nonutility subsidiaries.
North Central Wind Energy FacilitiesA joint PSO and SWEPCo project, which includes three Oklahoma wind facilities totaling approximately 1,485 MWs of wind generation.
NO2
Nitrogen dioxide.
NOLNet operating losses.
NOx
 Nitrogen oxide.
NPDESNational Pollutant Discharge Elimination System.
NRC Nuclear Regulatory Commission.
NSRNew Source Review.
OATT Open Access Transmission Tariff.
OCC Corporation Commission of the State of Oklahoma.
Ohio Phase-in-Recovery FundingOhio Phase-in-Recovery Funding LLC, a wholly-owned subsidiary of OPCo and a consolidated VIE formed for the purpose of issuing and servicing securitization bonds related to phase-in recovery property. In July 2019, the Ohio Phase-in Recovery funding securitization bonds matured.
iii


Term Meaning
   
OHTCoAEP Ohio Transmission Company, Inc., a wholly-owned AEPTCo transmission subsidiary.
Oklaunion Power StationA retired, single unit coal-fired generation plant totaling 650 MW located in Vernon, Texas. The plant was jointly-owned by AEP Texas, PSO and certain nonaffiliated entities.
OKTCoAEP Oklahoma Transmission Company, Inc., a wholly-owned AEPTCo transmission subsidiary.
OPCo Ohio Power Company, an AEP electric utility subsidiary.
OPEBOther Postretirement Benefits.
Operating AgreementAgreement, dated January 1, 1997, as amended, by and among PSO and SWEPCo governing generating capacity allocation, energy pricing, and revenues and costs of third-party sales.  AEPSC acts as the agent.
OTCOver-the-counter.
OVEC Ohio Valley Electric Corporation, which is 43.47% owned by AEP.
ParentAmerican Electric Power Company, Inc., the equity owner of AEP subsidiaries within the AEP consolidation.
PATH-WVPATH West Virginia Transmission Company, LLC, a joint venture-owned 50% by FirstEnergy and 50% by AEP.
PCAPower Coordination Agreement among APCo, I&M, KPCo and WPCo.
PJM Pennsylvania – New Jersey – Maryland regional transmission organization.
PMParticulate Matter.
PPAPurchase Power and Sale Agreement.
PSO Public Service Company of Oklahoma, an AEP electric utility subsidiary.
PTCProduction Tax Credits.
PUCO Public Utilities Commission of Ohio.
PUCT Public Utility Commission of Texas.
RacineA generation plant consisting of two hydroelectric generating units totaling 48 MWs located in Racine, Ohio and owned by AGR.
Reference Rate ReformThe global transition away from referencing the London Interbank Offered Rate and other interbank offered rates, and toward new reference rates that are more reliable and robust.
Registrant SubsidiariesAEP subsidiaries which are SEC registrants: AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO and SWEPCo.
RegistrantsSEC registrants: AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO and SWEPCo.
REP Texas Retail Electric Provider.
Restoration FundingAEP Texas Restoration Funding LLC, a wholly-owned subsidiary of AEP Texas and a consolidated VIE formed for the purpose of issuing and servicing securitization bonds related to storm restoration in Texas primarily caused by Hurricane Harvey.
Risk Management ContractsTrading and non-trading derivatives, including those derivatives designated as cash flow and fair value hedges.
Rockport Plant A generation plant, consisting of two 1,310 MW coal-fired generating units near Rockport, Indiana.  AEGCo and I&M jointly-own Unit 1.  In 1989, AEGCo and I&M entered into a sale-and-leaseback transaction with Wilmington Trust Company, an unrelated, unconsolidated trustee for Rockport Plant, Unit 2.
ROEReturn on Equity.
RPMReliability Pricing Model.
RTO Regional Transmission Organization, responsible for moving electricity over large interstate areas.
Sabine Sabine Mining Company, a lignite mining company that is a consolidated VIE for AEP and SWEPCo.
Santa Rita EastSanta Rita East Wind Holdings, LLC, a consolidated VIE whose sole purpose is to own and operate a 302 MW wind generation facility in west Texas in which AEP owns an 85% interest.
iv


Term Meaning
   
SEC U.S. Securities and Exchange Commission.
SEETSignificantly Excessive Earnings Test.
Sempra Renewables LLCSempra Renewables LLC, acquired in April 2019, consists of 724 MWs of wind generation and battery assets in the United States.
SIASystem Integration Agreement, effective June 15, 2000, as amended, provides contractual basis for coordinated planning, operation and maintenance of the power supply sources of the combined AEP.
SIPState Implementation Plan.
SNFSpent Nuclear Fuel.
SO2
 Sulfur dioxide.
SPP Southwest Power Pool regional transmission organization.
SSOStandard service offer.
State TranscosAEPTCo’s seven wholly-owned, FERC regulated, transmission only electric utilities, which are geographically aligned with AEP's existing utility operating companies.
SWEPCo Southwestern Electric Power Company, an AEP electric utility subsidiary.
SWTCoAEP Southwestern Transmission Company, Inc., a wholly-owned AEPTCo transmission subsidiary.
TA Transmission Agreement, effective November 2010, among APCo, I&M, KGPCo, KPCo, OPCo and WPCo with AEPSC as agent.
Tax ReformOn December 22, 2017, President Trump signed into law legislation referred to as the “Tax Cuts and Jobs Act” (the TCJA). The TCJA includes significant changes to the Internal Revenue Code of 1986, including a reduction in the corporate federal income tax rate from 35% to 21% effective January 1, 2018.
TCA Transmission Coordination Agreement dated January 1, 1997, by and among, PSO, SWEPCo and AEPSC, in connection with the operation of the transmission assets of the two public utility subsidiaries.
TCCFormerly AEP Texas Central Company; now a division of AEP Texas.
Texas Restructuring LegislationLegislation enacted in 1999 to restructure the electric utility industry in Texas.
TNC Formerly AEP Texas North Company; now a division of AEP Texas.
Transition FundingAEP Texas Central Transition Funding II LLC and AEP Texas Central Transition Funding III LLC, wholly-owned subsidiaries of TCC and consolidated VIE formed for the purpose of issuing and servicing securitization bonds related to Texas Restructuring Legislation. In July 2020, the final AEP Texas Central Transition Funding II LLC securitization bond matured.
Transource EnergyTransource Energy, LLC, a consolidated VIE formed for the purpose of investing in utilities which develop, acquire, construct, own and operate transmission facilities in accordance with FERC-approved rates.
TrentTrent Wind Farm LLC, a 156 MW wind electricity generation facility located between Abilene and Sweetwater in west Texas in which AEP owns a 100% interest.
Turk PlantJohn W. Turk, Jr. Plant, a 650 MW coal-fired plant in Arkansas that is 73% owned by SWEPCo.
UMWAUnited Mine Workers of America.
UPAUnit Power Agreement.
Utility Money Pool Centralized funding mechanism AEP uses to meet the short-term cash requirements of certain utility subsidiaries.
VIEVariable Interest Entity.
Virginia SCC Virginia State Corporation Commission.
WPCo Wheeling Power Company, an AEP electric utility subsidiary.
WVPSC Public Service Commission of West Virginia.
WVTCoAEP West Virginia Transmission Company, Inc., a wholly-owned AEPTCo transmission subsidiary.
v


FORWARD-LOOKING INFORMATION

This report made by the Registrants contains forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934.  Many forward-looking statements appear in “Item 7 – Management’s Discussion and Analysis of Financial Condition and Results of Operations,” but there are others throughout this document which may be identified by words such as “expect,” “anticipate,” “intend,” “plan,” “believe,” “will,” “should,” “could,” “would,” “project,” “continue” and similar expressions, and include statements reflecting future results or guidance and statements of outlook.  These matters are subject to risks and uncertainties that could cause actual results to differ materially from those projected.  Forward-looking statements in this document are presented as of the date of this document.  Except to the extent required by applicable law, management undertakes no obligation to update or revise any forward-looking statement.  Among the factors that could cause actual results to differ materially from those in the forward-looking statements are:

Changes in economic conditions, electric market demand and demographic patterns in AEP service territories.
The impact of pandemics, including COVID-19, and any associated disruption of AEP’s business operations due to impacts on economic or market conditions, electricity usage, employees, customers, service providers, vendors and suppliers.
Inflationary or deflationary interest rate trends.
Volatility in the financial markets, particularly developments affecting the availability or cost of capital to finance new capital projects and refinance existing debt.
The availability and cost of funds to finance working capital and capital needs, particularly during periods when the time lag between incurring costs and recovery is long and the costs are material.
Decreased demand for electricity.
Weather conditions, including storms and drought conditions, and the ability to recover significant storm restoration costs.
The cost of fuel and its transportation, the creditworthiness and performance of fuel suppliers and transporters and the cost of storing and disposing of used fuel, including coal ash and SNF.
The availability of fuel and necessary generation capacity and the performance of generation plants.
The ability to recover fuel and other energy costs through regulated or competitive electric rates.
The ability to build or acquire renewable generation, transmission lines and facilities (including the ability to obtain any necessary regulatory approvals and permits) when needed at acceptable prices and terms, including favorable tax treatment, and to recover those costs.
New legislation, litigation and government regulation, including changes to tax laws and regulations, oversight of nuclear generation, energy commodity trading and new or heightened requirements for reduced emissions of sulfur, nitrogen, mercury, carbon, soot or PM and other substances that could impact the continued operation, cost recovery and/or profitability of generation plants and related assets.
Evolving public perception of the risks associated with fuels used before, during and after the generation of electricity, including coal ash and nuclear fuel.
Timing and resolution of pending and future rate cases, negotiations and other regulatory decisions, including rate or other recovery of new investments in generation, distribution and transmission service and environmental compliance.
Resolution of litigation.
The ability to constrain operation and maintenance costs.
Prices and demand for power generated and sold at wholesale.
Changes in technology, particularly with respect to energy storage and new, developing, alternative or distributed sources of generation.
The ability to recover through rates any remaining unrecovered investment in generation units that may be retired before the end of their previously projected useful lives.
Volatility and changes in markets for coal and other energy-related commodities, particularly changes in the price of natural gas.
Changes in utility regulation and the allocation of costs within RTOs including ERCOT, PJM and SPP.
Changes in the creditworthiness of the counterparties with contractual arrangements, including participants in the energy trading market.
Actions of rating agencies, including changes in the ratings of debt.
vi


The impact of volatility in the capital markets on the value of the investments held by the pension, OPEB, captive insurance entity and nuclear decommissioning trust and the impact of such volatility on future funding requirements.
Accounting standards periodically issued by accounting standard-setting bodies.
Other risks and unforeseen events, including wars, the effects of terrorism (including increased security costs), embargoes, naturally occurring and human-caused fires, cyber security threats and other catastrophic events.
The ability to attract and retain the requisite work force and key personnel.

The forward-looking statements of the Registrants speak only as of the date of this report or as of the date they are made.  The Registrants expressly disclaim any obligation to update any forward-looking information, except as required by law.  For a more detailed discussion of these factors, see “Risk Factors” in Part I of this report.

Investors should note that the Registrants announce material financial information in SEC filings, press releases and public conference calls. Based on guidance from the SEC, the Registrants may use the Investors section of AEP’s website (www.aep.com) to communicate with investors about the Registrants. It is possible that the financial and other information posted there could be deemed to be material information. The information on AEP’s website is not part of this report.
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PART I

ITEM 1.   BUSINESS

GENERAL

Overview and Description of Major Subsidiaries

AEP was incorporated under the laws of the State of New York in 1906 and reorganized in 1925. It is a public utility holding company that owns, directly or indirectly, all of the outstanding common stock of its public utility subsidiaries and varying percentages of other subsidiaries.

The service areas of AEP’s public utility subsidiaries cover portions of the states of Arkansas, Indiana, Kentucky, Louisiana, Michigan, Ohio, Oklahoma, Tennessee, Texas, Virginia and West Virginia. Transmission networks are interconnected with extensive distribution facilities in the territories served. The public utility subsidiaries of AEP have traditionally provided electric service, consisting of generation, transmission and distribution, on an integrated basis to their retail customers. Restructuring laws in Michigan, Ohio and the ERCOT area of Texas have caused AEP public utility subsidiaries in those states to unbundle previously integrated regulated rates for their retail customers.

The member companies of the AEP System have contractual, financial and other business relationships with the other member companies, such as participation in the AEP System savings and retirement plans and tax returns, sales of electricity and transportation and handling of fuel. The companies of the AEP System also obtain certain accounting, administrative, information systems, engineering, financial, legal, maintenance and other services at cost from a common provider, AEPSC.

As of December 31, 2020, the subsidiaries of AEP had a total of 16,787 employees. Because it is a holding company rather than an operating company, AEP has no employees. The material subsidiaries of AEP are as follows:

AEP Texas

Organized in Delaware in 1925, AEP Texas is engaged in the transmission and distribution of electric power to approximately 1,068,000 retail customers through REPs in west, central and southern Texas.  As of December 31, 2020, AEP Texas had 1,570 employees.  Among the principal industries served by AEP Texas are petroleum and coal products manufacturing, chemical manufacturing, oil and gas extraction, pipeline transportation and primary metal manufacturing.  The territory served by AEP Texas also includes several military installations and correctional facilities.  AEP Texas is a member of ERCOT.  AEP Texas is part of AEP’s Transmission and Distribution Utilities segment.

AEPTCo

Organized in Delaware in 2006, AEPTCo is a holding company for the State Transcos. The State Transcos develop and own new transmission assets that are physically connected to the AEP System.  Individual State Transcos (a) have obtained the approvals necessary to operate in Indiana, Kentucky, Michigan, Ohio, Oklahoma and West Virginia, subject to any applicable siting requirements, (b) are authorized to submit projects for commission approval in Virginia and (c) have been granted consent to enter into a joint license agreement that will support investment in Tennessee. Neither AEPTCo nor its subsidiaries have any employees. Instead, AEPSC and certain AEP utility subsidiaries provide services to these entities. AEPTCo is part of the AEP Transmission Holdco segment.


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APCo

Organized in Virginia in 1926, APCo is engaged in the generation, transmission and distribution of electric power to approximately 964,000 retail customers in the southwestern portion of Virginia and southern West Virginia, and in supplying and marketing electric power at wholesale to other electric utility companies, municipalities and other market participants. APCo owns 6,629 MWs of generating capacity.  APCo uses its generation to serve its retail and other customers.  As of December 31, 2020, APCo had 1,652 employees. Among the principal industries served by APCo are coal-mining, primary metals, pipeline transportation, chemical manufacturing and paper manufacturing. APCo is a member of PJM.  APCo is part of AEP’s Vertically Integrated Utilities segment.

I&M

Organized in Indiana in 1907, I&M is engaged in the generation, transmission and distribution of electric power to approximately 602,000 retail customers in northern and eastern Indiana and southwestern Michigan, and in supplying and marketing electric power at wholesale to other electric utility companies, rural electric cooperatives, municipalities and other market participants.  I&M owns or leases 3,634 MWs of generating capacity, which it uses to serve its retail and other customers.  As of December 31, 2020, I&M had 2,217 employees. Among the principal industries served are primary metals, transportation equipment, chemical manufacturing, plastics and rubber products and fabricated metal product manufacturing.  I&M is a member of PJM.  I&M is part of AEP’s Vertically Integrated Utilities segment.

KPCo

Organized in Kentucky in 1919, KPCo is engaged in the generation, transmission and distribution of electric power to approximately 166,000 retail customers in eastern Kentucky, and in supplying and marketing electric power at wholesale to other electric utility companies, municipalities and other market participants.  KPCo owns 1,060 MWs of generating capacity.  KPCo uses its generation to serve its retail and other customers.  As of December 31, 2020, KPCo had 475 employees. Among the principal industries served are petroleum and coal products manufacturing, chemical manufacturing, coal-mining, oil and gas extraction and primary metals.  KPCo is a member of PJM.  KPCo is part of AEP’s Vertically Integrated Utilities segment.

KGPCo

Organized in Virginia in 1917, KGPCo provides electric service to approximately 49,000 retail customers in Kingsport and eight neighboring communities in northeastern Tennessee. KGPCo does not own any generating facilities and is a member of PJM. It purchases electric power from APCo for distribution to its customers. As of December 31, 2020, KGPCo had 52 employees. KGPCo is part of AEP’s Vertically Integrated Utilities segment.

OPCo

Organized in Ohio in 1907 and re-incorporated in 1924, OPCo is engaged in the transmission and distribution of electric power to approximately 1,507,000 retail customers in Ohio.  OPCo purchases energy and capacity at auction to serve generation service customers who have not switched to a competitive generation supplier.  As of December 31, 2020, OPCo had 1,646 employees.  Among the principal industries served by OPCo are primary metals, petroleum and coal products manufacturing, plastics and rubber products, chemical manufacturing, fabricated metal product manufacturing and data centers. OPCo is a member of PJM.  OPCo is part of AEP’s Transmission and Distribution Utilities segment.


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PSO

Organized in Oklahoma in 1913, PSO is engaged in the generation, transmission and distribution of electric power to approximately 565,000 retail customers in eastern and southwestern Oklahoma, and in supplying and marketing electric power at wholesale to other electric utility companies, municipalities, rural electric cooperatives and other market participants.  PSO owns 3,728 MWs of generating capacity, which it uses to serve its retail and other customers.  As of December 31, 2020, PSO had 1,023 employees. Among the principal industries served by PSO are paper manufacturing, oil and gas extraction, petroleum and coal products manufacturing, transportation equipment and pipeline transportation. PSO is a member of SPP.  PSO is part of AEP’s Vertically Integrated Utilities segment.

SWEPCo

Organized in Delaware in 1912, SWEPCo is engaged in the generation, transmission and distribution of electric power to approximately 545,000 retail customers in northeastern and panhandle of Texas, northwestern Louisiana and western Arkansas and in supplying and marketing electric power at wholesale to other electric utility companies, municipalities, rural electric cooperatives and other market participants. SWEPCo owns 5,034 MWs of generating capacity, which it uses to serve its retail and other customers.  As of December 31, 2020, SWEPCo had 1,440 employees. Among the principal industries served by SWEPCo are petroleum and coal products manufacturing, food manufacturing, paper manufacturing, oil and gas extraction and chemical manufacturing. The territory served by SWEPCo includes several military installations, colleges and universities. SWEPCo also owns and operates a lignite coal-mining operation. SWEPCo is a member of SPP.  SWEPCo is part of AEP’s Vertically Integrated Utilities segment.

WPCo

Organized in West Virginia in 1883 and re-incorporated in 1911, WPCo provides electric service to approximately 42,000 retail customers in northern West Virginia and in supplying and marketing electric power at wholesale to other market participants. WPCo owns 780 MWs of generating capacity which it uses to serve its retail and other customers. Among the principal industries served by WPCo are coal-mining, primary metals, pipeline transportation, chemical manufacturing and paper manufacturing. WPCo is a member of PJM. As of December 31, 2020, WPCo had 45 employees.  WPCo is part of AEP’s Vertically Integrated Utilities segment.

Service Company Subsidiary

AEPSC is a service company subsidiary that provides accounting, administrative, information systems, engineering, financial, legal, maintenance and other services at cost to AEP subsidiaries. The executive officers of AEP and certain of the executive officers of its public utility subsidiaries are employees of AEPSC. As of December 31, 2020, AEPSC had 6,295 employees.

Company Website and Availability of SEC Filings

Our principal corporate website address is www.aep.com. Information on our website is not incorporated by reference herein and is not part of this Form 10-K. We make available free of charge through our website our Annual Report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act as soon as reasonably practicable after such documents are electronically filed with, or furnished to, the SEC. The SEC maintains a website at www.sec.gov that contains reports, proxy and information statements and other information regarding AEP.

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Public Utility Subsidiaries by Jurisdiction

The following table illustrates certain regulatory information with respect to the jurisdictions in which the public utility subsidiaries of AEP operate:
Principal JurisdictionAEP Utility Subsidiaries Operating in that JurisdictionAuthorized Return on Equity (a)
FERCAEPTCo - PJM10.35%
AEPTCo - SPP10.50%
OhioOPCo10.20%(b)
West VirginiaAPCo9.75%
 WPCo9.75%
VirginiaAPCo9.20%
IndianaI&M9.70%
MichiganI&M9.86%
TexasAEP Texas9.40%
 SWEPCo9.60%
TennesseeKGPCo9.85%
KentuckyKPCo9.30%(c)
LouisianaSWEPCo9.80%
ArkansasSWEPCo9.45%
OklahomaPSO9.40%

(a)Identifies the predominant current authorized ROE, and may not include other, less significant, permitted recovery.  Actual ROE varies from authorized ROE.
(b)Authorized ROE was approved in OPCo’s last distribution base case. The authorized ROE for riders with an approved equity return (e.g. Distribution Investment Rider) is 10.00%.
(c)Final order received and made effective in January 2021 that approved an authorized ROE of 9.30%. The authorized ROE for riders with an approved equity return (Decommissioning Rider and the Environmental Surcharge) is 9.10%.

aep-20201231_g1.jpg
(a)Pretax income does not include intercompany eliminations.

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CLASSES OF SERVICE

The principal classes of service from which AEP’s subsidiaries derive revenues and the amount of such revenues during the years ended December 31, 2020, 2019 and 2018 are as follows:
 Years Ended December 31,
Description202020192018
 (in millions)
Vertically Integrated Utilities Segment   
Retail Revenues   
Residential Sales$3,614.8 $3,641.2 $3,818.6 
Commercial Sales2,021.0 2,151.1 2,223.7 
Industrial Sales2,023.5 2,178.3 2,261.3 
PJM Net Charges(0.1)(0.2)0.4 
Other Retail Sales155.9 179.4 186.8 
Total Retail Revenues7,815.1 8,149.8 8,490.8 
Wholesale Revenues   
Off-system Sales589.3 814.5 888.0 
Transmission249.5 200.7 263.7 
Total Wholesale Revenues838.8 1,015.2 1,151.7 
Other Electric Revenues85.8 93.8 93.7 
Provision for Rate Refund(21.7)(44.7)(210.1)
Other Operating Revenues35.2 31.6 30.6 
Sales to Affiliates126.2 121.4 88.8 
Total Revenues Vertically Integrated Utilities Segment$8,879.4 $9,367.1 $9,645.5 
Transmission and Distribution Utilities Segment   
Retail Revenues   
Residential Sales$2,114.9 $2,084.5 $2,213.6 
Commercial Sales1,049.5 1,148.8 1,266.7 
Industrial Sales390.0 426.5 517.2 
Other Retail Sales42.5 43.7 43.1 
Total Retail Revenues3,596.9 3,703.5 4,040.6 
Wholesale Revenues   
Off-system Sales60.6 93.0 119.3 
Transmission471.8 437.7 394.7 
Total Wholesale Revenues532.4 530.7 514.0 
Other Electric Revenues95.0 58.6 54.5 
Provision for Rate Refund2.3 12.5 (69.2)
Other Operating Revenues12.1 13.7 12.4 
Sales to Affiliates107.2 163.5 100.8 
Total Revenues Transmission and Distribution Utilities Segment$4,345.9 $4,482.5 $4,653.1 
AEP Transmission Holdco Segment
Transmission Revenues$315.1 $265.1 $291.3 
Other Electric Revenues0.4 0.3 0.3 
Other Operating Revenues0.6 0.1 0.3 
Sales to Affiliates901.4 812.9 555.5 
Provision for Rate Refund(18.7)(5.2)(43.3)
Total Revenues AEP Transmission Holdco Segment$1,198.8 $1,073.2 $804.1 
Generation & Marketing Segment   
Generation Revenues - Nonaffiliated$136.4 $264.4 $431.5 
Renewable Generation - Nonaffiliated85.7 77.7 44.5 
Retail, Trading and Marketing 
Affiliated104.6 135.7 122.2 
Nonaffiliated1,398.9 1,379.8 1,342.1 
Total Revenues Generation & Marketing Segment$1,725.6 $1,857.6 $1,940.3 

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AEP Texas
 Years Ended December 31,
Description202020192018
 (in millions)
Retail Revenues   
Residential Sales$562.3 $588.9 $594.6 
Commercial Sales365.9 424.0 426.6 
Industrial Sales119.9 133.3 131.0 
Other Retail Sales29.4 30.8 30.1 
Total Retail Revenues1,077.5 1,177.0 1,182.3 
Wholesale Revenues   
Transmission399.9 379.2 313.4 
Other Electric Revenues45.2 24.4 21.9 
Provision for Rate Refund2.3 (34.7)(31.3)
Total Electric Transmission and Distribution Revenues1,524.9 1,545.9 1,486.3 
Sales to Affiliates90.8 160.5 105.2 
Other Revenues3.2 2.9 3.8 
Total Revenues$1,618.9 $1,709.3 $1,595.3 

AEPTCo
 Years Ended December 31,
Description202020192018
 (in millions)
Transmission Revenues$264.4 $217.2 $212.8 
Other Electric Revenues0.4 0.3 0.3 
Other Operating Revenues0.6 0.1 0.2 
Sales to Affiliates896.3 806.7 598.9 
Provision for Rate Refund(16.0)(2.9)(36.1)
Total Revenues$1,145.7 $1,021.4 $776.1 

APCo
 Years Ended December 31,
Description202020192018
 (in millions)
Retail Revenues   
Residential Sales$1,250.4 $1,272.3 $1,372.1 
Commercial Sales517.0 562.2 596.3 
Industrial Sales553.3 594.5 620.7 
PJM Net Charges(0.3)(0.2)(0.2)
Other Retail Sales67.6 75.6 79.5 
Total Retail Revenues2,388.0 2,504.4 2,668.4 
Wholesale Revenues   
Off-system Sales118.1 124.9 116.4 
Transmission71.0 57.0 56.3 
Total Wholesale Revenues189.1 181.9 172.7 
Other Electric Revenues34.0 32.3 31.1 
Provision for Rate Refund(0.2)(10.4)(95.1)
Total Electric Generation, Transmission and Distribution Revenues2,610.9 2,708.2 2,777.1 
Sales to Affiliates174.7 205.3 181.4 
Other Revenues10.6 11.2 9.0 
Total Revenues$2,796.2 $2,924.7 $2,967.5 
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I&M
 Years Ended December 31,
Description202020192018
 (in millions)
Retail Revenues   
Residential Sales$794.1 $730.9 $736.5 
Commercial Sales499.4 494.9 489.3 
Industrial Sales547.5 551.4 570.6 
PJM Net Charges0.2 0.1 0.2 
Other Retail Sales6.6 7.3 7.2 
Total Retail Revenues1,847.8 1,784.6 1,803.8 
Wholesale Revenues   
Off-system Sales275.4 406.4 459.3 
Transmission31.0 19.3 18.4 
Total Wholesale Revenues306.4 425.7 477.7 
Other Electric Revenues11.3 14.4 15.7 
Provision for Rate Refund(0.2)(2.6)(24.6)
Total Electric Generation, Transmission and Distribution Revenues2,165.3 2,222.1 2,272.6 
Sales to Affiliates71.3 73.9 85.5 
Other Revenues5.2 10.7 12.6 
Total Revenues$2,241.8 $2,306.7 $2,370.7 

OPCo
 Years Ended December 31,
Description202020192018
 (in millions)
Retail Revenues   
Residential Sales$1,552.6 $1,495.6 $1,619.0 
Commercial Sales683.5 724.9 840.1 
Industrial Sales270.1 293.2 386.2 
Other Retail Sales13.1 12.9 13.0 
Total Retail Revenues2,519.3 2,526.6 2,858.3 
Wholesale Revenues   
Off-system Sales60.6 93.0 119.3 
Transmission68.8 58.5 61.4 
Total Wholesale Revenues129.4 151.5 180.7 
Other Electric Revenues49.9 34.2 32.7 
Provision for Rate Refund— 47.2 (37.9)
Total Electricity, Transmission and Distribution Revenues2,698.6 2,759.5 3,033.8 
Sales to Affiliates41.5 27.3 21.0 
Other Revenues9.0 10.8 8.6 
Total Revenues$2,749.1 $2,797.6 $3,063.4 

PSO
 Years Ended December 31,
Description202020192018
 (in millions)
Retail Revenues   
Residential Sales$579.8 $636.1 $668.5 
Commercial Sales320.4 377.3 401.1 
Industrial Sales221.2 296.5 308.5 
Other Retail Sales66.0 80.7 84.5 
Total Retail Revenues1,187.4 1,390.6 1,462.6 
Wholesale Revenues   
Off-system Sales15.1 39.5 36.3 
Transmission35.3 31.9 47.4 
Total Wholesale Revenues50.4 71.4 83.7 
Other Electric Revenues10.4 9.6 10.3 
Provision for Rate Refund(2.1)(2.0)(19.0)
Total Electric Generation, Transmission and Distribution Revenues1,246.1 1,469.6 1,537.6 
Sales to Affiliates5.2 6.1 5.4 
Other Revenues14.8 6.1 4.3 
Total Revenues$1,266.1 $1,481.8 $1,547.3 
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SWEPCo
 Years Ended December 31,
Description202020192018
 (in millions)
Retail Revenues   
Residential Sales$637.4 $645.3 $666.0 
Commercial Sales471.5 490.6 502.6 
Industrial Sales332.1 342.3 346.2 
Other Retail Sales9.1 9.1 8.9 
Total Retail Revenues1,450.1 1,487.3 1,523.7 
Wholesale Revenues   
Off-system Sales162.0 194.7 216.8 
Transmission87.0 72.6 94.2 
Total Wholesale Revenues249.0 267.3 311.0 
Other Electric Revenues16.5 20.6 20.9 
Provision for Rate Refund(19.0)(30.6)(63.7)
Total Electric Generation, Transmission and Distribution Revenues1,696.6 1,744.6 1,791.9 
Sales to Affiliates39.0 4.9 28.4 
Other Revenues2.9 1.4 1.6 
Total Revenues$1,738.5 $1,750.9 $1,821.9 

FINANCING

General

Companies within the AEP System generally use short-term debt to finance working capital needs.  Short-term debt may also be used to finance acquisitions, construction and redemption or repurchase of outstanding securities until such needs can be financed with long-term debt.  In recent history, short-term funding needs have been provided for by cash on hand and AEP’s commercial paper program.  Funds are made available to subsidiaries under the AEP corporate borrowing program.  Certain public utility subsidiaries of AEP also sell accounts receivable to provide liquidity.  See “Financial Condition” section of Management’s Discussion and Analysis of Financial Condition and Results of Operations included in the 2020 Annual Report for additional information.

AEP’s revolving credit agreement (which backstops the commercial paper program) includes covenants and events of default typical for this type of facility, including a maximum debt/capital test.  In addition, the acceleration of AEP’s payment obligations, or the obligations of certain of its major subsidiaries, prior to maturity under any other agreement or instrument relating to debt outstanding in excess of $50 million, would cause an event of default under the credit agreement. As of December 31, 2020, AEP was in compliance with its debt covenants.  With the exception of a voluntary bankruptcy or insolvency, any event of default has either or both a cure period or notice requirement before termination of the agreement.  A voluntary bankruptcy or insolvency of AEP or one of its significant subsidiaries would be considered an immediate termination event.  See “Financial Condition” section of Management’s Discussion and Analysis of Financial Condition and Results of Operations included in the 2020 Annual Report for additional information.

AEP’s subsidiaries have also utilized, and expect to continue to utilize, additional financing arrangements, such as securitization financings and leasing arrangements, including the leasing of coal transportation equipment and facilities.

ENVIRONMENTAL AND OTHER MATTERS

General

AEP subsidiaries are currently subject to regulation by federal, state and local authorities with regard to air and water-quality control and other environmental matters, and are subject to zoning and other regulation by local authorities.  The environmental issues that management believes are potentially material to the AEP System are outlined below.

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Clean Water Act Requirements

Operations for AEP subsidiaries are subject to the CWA, which prohibits the discharge of pollutants into waters of the United States except pursuant to appropriate permits and regulates systems that withdraw surface water for use in power plants.  In 2014, the Federal EPA issued a final rule setting forth standards for water withdrawals at existing power plants that is intended to reduce mortality of aquatic organisms pinned against a plant’s cooling water intake screen (impingement) or entrained in the cooling water.  The standards affect all plants withdrawing more than two million gallons of cooling water per day.  A schedule for compliance with the standard is established by the permit agency and incorporated in NPDES permits.

In November 2015, the Federal EPA issued a final rule revising effluent limitation guidelines for electricity generating facilities. The rule established limits on FGD wastewater, fly ash and bottom ash transport water and flue gas mercury control wastewater to be imposed in NPDES permits as soon as possible after November 2018 and no later than December 2023.  The Federal EPA further revised the rule in August 2020 for FGD wastewater and bottom ash transport water extending the compliance date to December 2025 and establishing additional options. In January 2020, the Federal EPA issued a final rule revising the scope of the “waters of the United States” subject to CWA regulation. See “Environmental Issues - Clean Water Act Regulations” section of Management’s Discussion and Analysis of Financial Condition and Results of Operations included in the 2020 Annual Report for additional information.

Coal Ash Regulation

AEP’s operations produce a number of different coal combustion by-products, including fly ash, bottom ash, gypsum and other materials.  A rule by the Federal EPA regulates the disposal and beneficial re-use of coal combustion residuals, including fly ash and bottom ash generated at coal-fired electric generating units.  The rule requires certain standards for location, groundwater monitoring and dam stability to be met at landfills and certain surface impoundments at operating facilities. If existing disposal facilities cannot meet these standards, they will be required to close. See “Environmental Issues - Coal Combustion Residual Rule” section of Management’s Discussion and Analysis of Financial Condition and Results of Operations included in the 2020 Annual Report for additional information.

Clean Air Act Requirements

The CAA establishes a comprehensive program to protect and improve the nation’s air quality and control mobile and stationary sources of air emissions.  The major CAA programs affecting AEP’s power plants are described below.  The states implement and administer many of these programs and could impose additional or more stringent requirements.

The Acid Rain Program

The CAA includes a cap-and-trade emission reduction program for SO2 emissions from power plants and requirements for power plants to reduce NOx emissions through the use of available combustion controls, collectively called the Acid Rain Program. AEP continues to meet its obligations under the Acid Rain Program through the installation of controls, use of alternate fuels and participation in the emissions allowance markets. 

National Ambient Air Quality Standards

The CAA requires the Federal EPA to review the available scientific data for criteria pollutants periodically and establish a concentration level in the ambient air for those substances that is adequate to protect the public health and welfare with an extra safety margin.  The Federal EPA also can list additional pollutants and develop concentration levels for them.  These concentration levels are known as NAAQS.

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Each state identifies the areas within its boundaries that meet the NAAQS (attainment areas) and those that do not (non-attainment areas).  Each state must develop a SIP to bring non-attainment areas into compliance with the NAAQS and maintain good air quality in attainment areas.  All SIPs are submitted to the Federal EPA for approval.  If a state fails to develop adequate plans, the Federal EPA develops and implements a plan.  As the Federal EPA reviews the NAAQS and establishes new concentration levels, the attainment status of areas can change and states may be required to develop new SIPs.  See “Environmental Issues - Clean Air Act Requirements” section of Management’s Discussion and Analysis of Financial Condition and Results of Operations included in the 2020 Annual Report for additional information.

Hazardous Air Pollutants (HAP)

The CAA also requires the Federal EPA to investigate HAP emissions from the electric utility sector and submit a report to Congress to determine whether those emissions should be regulated. In 2011, the Federal EPA issued a rule setting Maximum Achievable Control Technology standards for new and existing coal and oil-fired utility units and New Source Performance Standards for emissions from new and modified power plants.  In 2014, the U.S. Supreme Court determined that the Federal EPA acted unreasonably in refusing to consider costs in determining if it was appropriate and necessary to regulate HAP emissions from electric generating units. The Federal EPA has engaged in additional rulemaking activity but the 2011 rule remains in effect. See “Environmental Issues - Mercury and Other Hazardous Air Pollutants Regulation” section of Management’s Discussion and Analysis of Financial Condition and Results of Operations included in the 2020 Annual Report for additional information.

Regional Haze

The CAA establishes visibility goals for certain federally designated areas, including national parks, and requires states to submit SIPs that will demonstrate reasonable progress toward preventing impairment of visibility in these protected areas.  In 2005, the Federal EPA issued its Clean Air Visibility Rule, detailing how the CAA’s best available retrofit technology requirements will be applied to facilities built between 1962 and 1977 that emit more than 250 tons per year of certain pollutants in specific industrial categories, including power plants.

PSO executed a settlement with the Federal EPA and the State of Oklahoma to comply with Regional Haze program requirements in Oklahoma, and the settlement is now codified in the Oklahoma SIP and approved by the Federal EPA. The Federal EPA disapproved portions of the Arkansas and Texas SIPs, and finalized FIPs for both states.  Arkansas submitted and received approval of a revised SIP, and the Federal EPA developed a revised FIP for Texas. See “Environmental Issues - Clean Air Act Requirements” section of Management’s Discussion and Analysis of Financial Condition and Results of Operations included in the 2020 Annual Report for additional information.

Climate Change

AEP has taken action to reduce and offset CO2 emissions from its generating fleet and expects CO2 emissions from its operations to continue to decline due to the retirement of coal-fired generation units, and actions taken to diversify the generation fleet and increase energy efficiency where there is regulatory support for such activities. In 2021, AEP announced revised intermediate and long-term CO2 emission reduction goals, based on the output of the company’s integrated resource plans, which take into account economics, customer demand, regulations, grid reliability and resiliency, and reflect the company’s current business strategy. The intermediate goal is an 80% reduction from 2000 CO2 emission levels from AEP generating facilities by 2030; the long-term goal is net-zero CO2 emissions from AEP generating facilities by 2050. AEP’s total estimated CO2 emissions in 2020 were approximately 44 million metric tons, a 73% reduction from AEP’s 2000 CO2 emissions. AEP will publish a new report in 2021 on the results of a climate change scenario analysis.

To date, the Federal EPA has twice taken action to regulate CO2 emissions from new and existing fossil fueled electric generating units under the existing provisions of the CAA.  The Clean Power Plan was adopted in October 2015 but the U.S. Supreme Court issued a stay of its implementation, including all of the deadlines for submission
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of initial or final state plans. The Clean Power Plan was repealed by the Federal EPA in 2019 and replaced by the Affordable Clean Energy (ACE) Rule, which changed the Federal EPA’s approach to regulating CO2 emissions from existing coal-fired generating units. In January 2021, the ACE Rule was vacated by the U.S. Court of Appeals for the District of Columbia Circuit and remanded to the Federal EPA for further proceedings. It is too soon to predict how the Federal EPA will respond to the court’s remand. Management expects emissions to continue to decline over time as AEP diversifies generating sources and operates fewer coal units.  The projected decline in coal-fired generation is due to a number of factors, including the ongoing cost of operating older units, the relative cost of coal and natural gas as fuel sources, increasing environmental regulations requiring significant capital investments and changing commodity market fundamentals.

Transforming AEP’s Generation Fleet

The electric utility industry is in the midst of an historic transformation, driven by changing customer needs, policy demands, demographics, competitive offerings, technologies and commodity prices. AEP is also transforming to be more agile and customer-focused as a valued provider of energy solutions.  AEP’s long-term commitment to reduce CO2 emissions reflects the current direction of the company’s resource plans to meet those needs as well a new climate change scenario analysis to be published in 2021.  AEP’s exposure to carbon regulation has been greatly reduced over the last several years.  From 2000 to 2020, AEP’s CO2 emissions declined 73%.  In 2020, coal represented 44% of AEP’s generating capacity compared with 70% in 2005. Management expects the percentage of AEP’s generating resources fueled by coal will continue to decline and to represent only 24% of generating capacity by 2030. The long-term goal is net-zero CO2 emissions from AEP generating facilities by 2050.  Transforming AEP’s generation portfolio to include, where there is regulatory support, more renewable energy and focusing on the efficient use of energy, demand response, distributed resources and technology solutions to more efficiently manage the grid over time is part of this strategy.

The graph below summarizes AEP’s generation capacity by resource type for the years 1999, 2005 and 2020:
aep-20201231_g2.jpg
(a)    Energy Efficiency/Demand Response represents avoided capacity rather than physical assets.


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Renewable Sources of Energy

The states AEP serves, other than Kentucky, West Virginia and Tennessee, have established mandatory or voluntary programs to increase the use of energy efficiency, alternative energy or renewable energy sources.

As of December 31, 2020, AEP’s regulated utilities had long-term contracts for 2,750 MWs of wind, 80 MWs of hydro, and 10 MWs of solar power delivering renewable energy to the companies’ customers. In addition, I&M owns four solar projects that make up I&M’s 16 MW Clean Energy Solar Pilot Project. Management actively manages AEP’s compliance position and is on pace to meet the relevant requirements or benchmarks in each applicable jurisdiction.

In 2020, PSO received approval from the OCC and SWEPCo received approval from the APSC and LPSC to acquire the North Central Wind Energy Facilities, comprised of three Oklahoma wind facilities totaling 1,485 MWs, on a fixed cost turn-key basis at completion. Both the APSC and LPSC approved the flex-up option, agreeing to acquire the Texas portion, which the PUCT denied. PSO will own 45.5% and SWEPCo will own 54.5% of the project, which will cost approximately $2 billion.

In May 2020, the IRS issued a notice extending the “Continuity Safe Harbor” deadlines for qualifying renewable energy projects that began construction in 2016 and 2017 by one year as many projects are facing supply chain and other project development delays caused by COVID-19. Under the May 2020 IRS notice, qualifying renewable energy projects that began construction in 2016 and 2017 and which are placed in-service by the end of 2021 and 2022, respectively, will satisfy the Continuity Safe Harbor. Provided that each facility does satisfy the Continuity Safe Harbor, under the current IRS guidance, the 199 MW wind facility will qualify for 100% of the federal PTC, and the remaining two wind facilities, totaling 1,286 MWs, will qualify for 80% of the federal PTC.

Having regulatory approval, and the expectation that all three wind facilities will be eligible for the IRS extension of the “Continuity Safe Harbor,” PSO and SWEPCo are proceeding with the full 1,485 MW development of these three projects. The 199 MW wind facility is targeted to be acquired and placed in-service in March 2021. The 287 MW wind facility is targeted to be acquired and placed in-service in December 2021 and the 999 MW wind facility is targeted to be acquired and placed in-service between December 2021 and April 2022.

The growth of AEP’s renewable generation portfolio reflects the company’s strategy to diversify generation resources to provide clean energy options to customers that meet both their energy and capacity needs.  In addition to gradually reducing AEP’s reliance on coal-fueled generating units, the growth of renewables and natural gas helps AEP to maintain a diversity of generation resources.

The integrated resource plans filed with state regulatory commissions by AEP’s regulated utility subsidiaries reflect AEP’s renewable strategy to balance reliability and cost with customers’ desire for clean energy in a carbon-constrained world.  AEP has committed significant capital investments to modernize the electric grid and integrate these new resources.  Transmission assets of the AEP System interconnect approximately 16,300 MWs of renewable energy resources.  AEP’s transmission development initiatives are designed to facilitate the interconnection of additional renewable energy resources.

AEP Energy Supply, LLC is a holding company with several divisions, including AEP Renewables and AEP OnSite Partners.

AEP Renewables develops, owns and operates utility scale renewable projects backed with long-term contracts with creditworthy counterparties throughout the United States.  AEP Renewables works directly with stakeholders to ensure that customers have clean, sustainable renewable energy to meet their environmental goals.  As of December 31, 2020, AEP Renewables owned projects operating in 11 states, including approximately 1,307 MWs of installed wind capacity and 90 MWs of installed solar capacity.  These figures include the 2020 acquisition of an additional 10% interest, or approximately 30 MWs, of Santa Rita East wind generation located in west Texas. In October 2019, AEP Renewables entered into an agreement to construct Flat Ridge 3, a wind farm in Kansas.  The 128 MW facility is expected to reach commercial operation by May 2021.

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AEP OnSite Partners works directly with wholesale and large retail customers to provide tailored solutions to reduce their energy costs based upon market knowledge, innovative applications of technology and deal structuring capabilities.  AEP OnSite Partners targets opportunities in distributed solar, combined heat and power, energy storage, waste heat recovery, energy efficiency, peaking generation and other energy solutions that create value for customers.  AEP OnSite Partners pursues and develops behind the meter projects with creditworthy customers.  As of December 31, 2020, AEP OnSite Partners owned projects located in 21 states, including approximately 152 MWs of installed solar capacity, and approximately 9 MWs of solar projects under construction.

Competitive Renewable Generation Facilities
Size of
Energy Resource
AEP Energy Supply, LLC DivisionRenewable
Energy Resource
LocationIn-Service or
Under Construction
1,307 MWAEP RenewablesWindEight states (a)In-service
128 MWAEP RenewablesWindKansasUnder Construction
20 MWAEP RenewablesSolarCaliforniaIn-service
20 MWAEP RenewablesSolarUtahIn-service
50 MWAEP RenewablesSolarNevadaIn-service
152 MWAEP OnSite PartnersSolarSixteen states (b)In-service
9 MWAEP OnSite PartnersSolarTwo states (c)Under Construction

(a)    Colorado, Hawaii, Indiana, Kansas, Michigan, Minnesota, Pennsylvania, and Texas.
(b)    California, Colorado, Florida, Hawaii, Illinois, Iowa, Minnesota, Nebraska, New Hampshire, New Jersey, New Mexico, New York, Ohio, Rhode Island, Texas and Vermont.
(c)    Ohio and Wisconsin.

End Use Energy Efficiency

AEP has reduced energy consumption and peak demand through the introduction of additional energy efficiency and demand response programs.  These programs, commonly referred to as demand-side management, were implemented in jurisdictions where appropriate cost recovery was available.  AEP’s operating companies’ programs have reduced annual consumption by over 9 million MWhs and peak demand by approximately 2,900 MWs since 2008.  AEP estimates that its operating companies spent approximately $1.5 billion during that period to achieve these levels.

Energy efficiency and demand reduction programs have received regulatory support in most of the states AEP serves. Appropriate cost recovery will be essential for AEP operating companies to continue and expand these consumer offerings. Appropriate recovery of program costs, lost revenues and an opportunity to earn a reasonable return ensures that energy efficiency programs are considered equally with supply side investments.  As AEP continues to transition to a cleaner, more efficient energy future, energy efficiency and demand response programs will continue to play an important role in how the company serves its customers. AEP believes its experience providing robust energy efficiency programs in several states positions the company to be a cost-effective provider of these programs as states develop their implementation plans.

Corporate Governance

In response to environmental issues and in connection with its assessment of AEP’s strategic plan, the Board of Directors continually reviews the risks posed by new environmental rules and requirements that could accelerate the retirement of coal-fired generation assets. The Board of Directors is informed of any new environmental regulations and proposed regulation or legislation that would significantly affect AEP.  The Board’s Committee on Directors and Corporate Governance oversees AEP’s annual Corporate Accountability Report, which includes information about AEP’s environmental, social, governance and financial performance. AEP set CO2 emission reduction goals in 2018 after considering input from corporate governance outreach effort with shareholders.

In February 2021, AEP announced new intermediate and long-term CO2 emission reduction goals, based on the output of the company’s integrated resource plans, which take into account economics, customer demand, grid reliability and resiliency, regulations and the company’s current business strategy. The intermediate goal is an 80%
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reduction from 2000 CO2 emission levels from AEP generating facilities by 2030; the long-term goal is net-zero CO2 emissions from AEP generating facilities by 2050. AEP has made significant progress in reducing CO2 emissions from its power generation fleet and expects its emissions to continue to decline. Technological advances, including advanced energy storage, modular nuclear, and green hydrogen, and public policies are among the factors that will determine how quickly AEP can achieve net-zero emissions while continuing to provide reliable, affordable power for customers. AEP will publish a new report in 2021 on the results of a climate change scenario analysis.

Other Environmental Issues and Matters

The Comprehensive Environmental Response, Compensation and Liability Act of 1980 imposes costs for environmental remediation upon owners and previous owners of sites, as well as transporters and generators of hazardous material disposed of at such sites.  See “The Comprehensive Environmental Response Compensation and Liability Act (Superfund) and State Remediation” section of Note 6 included in the 2020 Annual Report for additional information.

Environmental Investments

Investments related to improving AEP System plants’ environmental performance and compliance with air and water quality standards during 2018, 2019 and 2020 and the current estimate for 2021 are shown below. These investments include both environmental as well as other related spending. Estimated construction expenditures are subject to periodic review and modification and may vary based on the ongoing effects of regulatory constraints, environmental regulations, business opportunities, market volatility, economic trends and the ability to access capital.  In addition to the amounts set forth below, AEP expects to make substantial investments in future years in connection with the modification and addition at generation plants’ facilities for environmental quality controls.  Such future investments are needed in order to comply with air and water quality standards that have been adopted and have deadlines for compliance after 2020 or have been proposed and may be adopted.  Future investments could be significantly greater if emissions reduction requirements are accelerated or otherwise become more stringent. The cost of complying with applicable environmental laws, regulations and rules is expected to be material to the AEP System. AEP typically recovers costs of complying with environmental standards from customers through rates in regulated jurisdictions.  Failure to recover these costs could reduce future net income and cash flows and possibly harm AEP’s financial condition.  See “Environmental Issues” section of Management’s Discussion and Analysis of Financial Condition and Results of Operations and Note 6 - Commitments, Guarantees and Contingencies included in the 2020 Annual Report for additional information.
Historical and Projected Environmental Investments
 2018201920202021
 ActualActualActualEstimate (b)
 (in millions)
AEP (a)$115.6 $167.1 $102.2 $133.8 
AEP Texas— (0.2)— — 
APCo20.4 23.8 21.3 60.6 
I&M31.1 56.4 31.8 16.8 
SWEPCo14.1 10.5 (3.6)8.8 

(a)Includes expenditures of the subsidiaries shown and other subsidiaries not shown. The figures reflect construction expenditures, not investments in subsidiary companies.
(b)Estimated amounts are exclusive of debt AFUDC.

Management continues to refine the cost estimates of complying with air and water quality standards and other impacts of the environmental proposals. The following cost estimates for the years 2021 through 2027 will change depending on the timing of implementation and whether the Federal EPA provides flexibility in the final rules.  These cost estimates will also change based on: (a) potential state rules that impose more stringent standards,
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(b) additional rulemaking activities in response to court decisions, (c) actual performance of the pollution control technologies installed, (d) changes in costs for new pollution controls, (e) new generating technology developments, (f) total MWs of capacity retired and replaced, including the type and amount of such replacement capacity and (g) other factors. Management’s current ranges of estimates of new major environmental investments beginning in 2021, exclusive of debt AFUDC, are set forth below:
Projected (2021 - 2027)
Environmental Investment
CompanyLowHigh
(in millions)
AEP$350 $700 
APCo175 290 
I&M25 45 
PSO10 
SWEPCo45 90 

HUMAN CAPITAL MANAGEMENT

Attracting, developing and retaining employees with the skills and experience needed to provide service to our customers efficiently and effectively is crucial to our long-term success and is central to our long-term strategy. AEP invests in employees and continues to build a high performance and inclusive culture that inspires leadership, encourages innovative thinking and welcomes everyone.

The following table shows AEP’s number of employees by subsidiary as of December 31, 2020:

SubsidiaryNumber of Employees
AEPSC6,295 
AEP Texas1,570 
APCo1,652 
I&M2,217 
OPCo1,646 
PSO1,023 
SWEPCo1,440 
Other944 
Total AEP16,787 

Of AEP’s 16,787 employees, less than 1% are Traditionalists (born before 1946), approximately 27% are Baby Boomers (born 1946-1964), approximately 37% are Generation X (born 1965-1980), approximately 34% are Millennials (born 1981-1996) and approximately 1% are Generation Z (born after 1996).

Safety

Achieving Zero Harm means every employee returns home at the end of their shift in the same or better condition than when they came to work. Zero Harm is what we value most and commit to wholeheartedly. It is hard work, as it requires full focus every moment of every day. We hold ourselves accountable and we are always striving to be better. For AEP, Zero Harm is not an option; it is a mandate we live by. AEP has put tools, training and processes in place to strengthen our safety-first culture and mindset. AEP’s focus is on learning from events and developing leading indicators to be even more proactive in preventing harm. One common industry safety metric utilized by AEP to track incidents is the Days Away/Restricted or Transferred (DART) rate. A DART event is an event that results in one or more lost days, one or more restricted days or results in an employee transferring to a different job within the company. The DART rate is a mathematical calculation (number of DART events multiplied by 200,000 work hours and divided by total YTD hours worked) that describes the number of recordable injuries per 100 full-time employees. In 2020, AEP recognized its best safety performance in the past five years with an employee DART Rate of 0.310.
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Diversity and Inclusion

AEP is committed to cultivating a diverse and inclusive environment that supports the development and advancement of all. We foster an inclusive workplace that encourages diversity of thought, culture and background, and actively work to eliminate unconscious biases. We believe our workforce should reflect the diversity of our customers and the communities we serve so that we may better understand how to tailor our services to meet their demands and expectations. As of December 31, 2020, females comprised approximately 20% of AEP’s workforce while approximately 19% was represented by minorities.

AEP has taken actions to denounce all forms of racism in the wake of the racial and social unrest across the country. AEP Chief Executive Officer (CEO) Nicholas Akins joined more than 1,400 other CEOs as a signatory to the CEO Action for Diversity and Inclusion pledge, the largest CEO-driven business commitment to advancing diversity and inclusion within the workplace. To accelerate our diversity and inclusion strategy, AEP has initiated a “Seize the Moment: Let’s Keep the Momentum Going” action plan that included candid conversations about race, Town Hall webcasts and “Let’s Talk” discussions with the top 20 African American leaders at AEP.

Culture

AEP believes in doing the right thing every time for our customers, each other and our future. AEP leaders at all levels are responsible for fostering an environment that supports a positive culture and for acting in a manner that positively models it. Employees are given an opportunity to share their perspectives by participating in the Employee Culture Survey, administered by Gallup, Inc., that measures the progress we are making in improving our culture. In addition to engagement, the survey measures well-being and inclusiveness. In 2020, 93% of our organization participated in the survey and we improved our grand mean score to the top decile compared to Gallup’s overall company database. Company executives also have candid meetings with employees to discuss our challenges, opportunities, what is going well and what can be even better.

Employee Resource Groups

One of the best ways for AEP to demonstrate our commitment to a trusting and inclusive work environment is to empower employees to form and participate in Employee Resource Groups (ERG). The ERGs at AEP include Abled and Disabled Allies Partnering Together, the African-American ERG, the Asian-American ERG, the Hispanic Origin Latin American ERG, the Military Veteran ERG, the Native American ERG and the Pride Partnership. Our ERGs reflect the diverse makeup of our workforce and enable us to gain valuable insight into the diverse communities we serve. They also help increase engagement across AEP by providing employees with a safe space to discuss work-related issues and to develop innovative solutions. ERGs also play an active role in AEP’s diversity and inclusion efforts, including recruitment of new employees. In addition to the ERG’s, AEP also sponsors the AEP Women’s Leadership Council. The mission of this council is to educate, inspire and encourage women to build confidence and reflect on their goals as they strive for career and personal growth.

Training and Professional Development

At AEP, we are preparing our workforce for the future by providing opportunities to learn new skills and engaging higher education institutions to better prepare the next generation with the skills that we will need. AEP has training alliances with several community colleges, universities and vocational and technical schools across our service territory. We work with these institutions to develop academic programs that will prepare employees for upward mobility opportunities and to attract external job seekers interested in careers in our industry. AEP also provides a broad range of training and assistance that supports lifelong learning and transition development. This is especially important as we move closer toward a digital future that requires a more flexible, innovative and diverse workforce. AEP has robust processes to achieve this, including ongoing performance coaching, operational skills training, resources to support our commitment to environment, safety and health, job progression training, tuition assistance, and other forms of training that help employees improve their skills and become better leaders.
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Compensation and Benefits

AEP recognizes the importance of our employees to our success and we offer physical, financial and other health, wellness and assistance programs to our associates and their families to help them thrive at home and work. We ensure the pay we offer is competitive in the marketplace by using an overall market pricing process. In addition to competitive wages, nearly all AEP employees participate in an annual incentive program that rewards outstanding performance and achievement of business goals. Our incentive compensation provides financial rewards to those who contribute to business results and meet or exceed their personal performance goals, which fosters a high performance culture. AEP also offers employees physical and mental health programs, including medical, dental and life insurance, along with a health and well-being program to help employees and their families stay healthy and feeling their best. Additionally, AEP’s retirement programs position our associates for financial stability in retirement.

Labor Relations

Nearly one fourth of AEP’s workforce is represented by labor unions. We value the relationships we have with our unionized employees and believe in a trusting, collaborative and respectful partnership. We are working with our labor partners to strengthen these relationships to ensure we have a culture that attracts and supports employees who can adapt to the rapid changes occurring in our company and industry. Our partnership with labor unions is critical to meeting the growing expectations of our customers and adapting to the challenges of rapidly changing technologies.

BUSINESS SEGMENTS

AEP’s Reportable Segments

AEP’s primary business is the generation, transmission and distribution of electricity.  Within its Vertically Integrated Utilities segment, AEP centrally dispatches generation assets and manages its overall utility operations on an integrated basis because of the substantial impact of cost-based rates and regulatory oversight.  Intersegment sales and transfers are generally based on underlying contractual arrangements and agreements. AEP’s reportable segments are as follows:

Vertically Integrated Utilities
Transmission and Distribution Utilities
AEP Transmission Holdco
Generation & Marketing

The remainder of AEP’s activities is presented as Corporate and Other, which is not considered a reportable segment. See Note 9 - Business Segments included in the 2020 Annual Report for additional information on AEP’s segments.


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VERTICALLY INTEGRATED UTILITIES

GENERAL

AEP’s vertically integrated utility operations are engaged in the generation, transmission and distribution of electricity for sale to retail and wholesale customers through assets owned and operated by AEGCo, APCo, I&M, KGPCo, KPCo, PSO, SWEPCo and WPCo.  AEPSC, as agent for AEP’s public utility subsidiaries, performs marketing, generation dispatch, fuel procurement and power-related risk management and trading activities on behalf of each of these subsidiaries.

ELECTRIC GENERATION

Facilities

As of December 31, 2020, AEP’s vertically integrated public utility subsidiaries owned or leased approximately 22,000 MWs of domestic generation.  See Item 2 – Properties for more information regarding the generation capacity of vertically integrated public utility subsidiaries.

Fuel Supply

The following table shows the owned and leased generation sources by type (including wind purchase agreements), on an actual net generation (MWhs) basis, used by the Vertically Integrated Utilities:
 202020192018
Coal and Lignite45%54%58%
Nuclear24%19%18%
Natural Gas18%16%14%
Renewables13%11%10%

A price increase/decrease in one or more fuel sources relative to other fuels, as well as the addition of renewable resources or retirement of traditional fossil fuel units, may result in the decreased/increased use of other fuels.  AEP’s overall 2020 fossil fuel costs for the Vertically Integrated Utilities decreased 3% on a dollar per MMBtu basis from 2019.

Coal and Lignite

AEP’s Vertically Integrated Utilities procure coal and lignite under a combination of purchasing arrangements including long-term contracts, affiliate operations and spot agreements with various producers, marketers and coal trading firms.  Coal consumption in 2020 decreased approximately 27% from 2019 mainly due to lower dispatching of coal generation from weaker power market prices.

Management believes that the Vertically Integrated Utilities will be able to secure and transport coal and lignite of adequate quality and quantities to operate their coal and lignite-fired units. Through subsidiaries, AEP owns, leases or controls 3,016 railcars, 411 barges, 6 towboats and a coal handling terminal with approximately 18 million tons of annual capacity to move and store coal for use in AEP generating facilities.

Spot market prices for coal weakened during the first half of 2020 before stabilizing or slightly rebounding in the second half of 2020. The decreased spot coal prices reflect lower demand for domestic and export coal. AEP’s strategy for purchasing coal includes layering in supplies over time. The price impact of this process is reflected in subsequent periods and can occasionally cause current spot market prices to be trending opposite to the price of coal delivered. The price paid for coal delivered in 2020 increased approximately 18% from 2019 mainly due to lignite mine related activities and closure costs.

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The following table shows the amount of coal and lignite delivered to the Vertically Integrated Utilities’ plants during the past three years and the average delivered price of coal and lignite purchased by the Vertically Integrated Utilities:
 202020192018
Total coal and lignite delivered to the plants (in millions of tons)19.430.429.0 
Average cost per ton of coal and lignite delivered$53.95 $45.85 $43.21 

The coal supplies at the Vertically Integrated Utilities plants vary from time to time depending on various factors, including, but not limited to, demand for electric power, unit outages, transportation infrastructure limitations, space limitations, plant coal consumption rates, availability of acceptable coals, labor issues and weather conditions, which may interrupt production or deliveries. As of December 31, 2020, the Vertically Integrated Utilities’ coal inventory was approximately 64 days of full load burn. While inventory targets vary by plant and are changed as necessary, the current coal inventory target for the Vertically Integrated Utilities is approximately 30 days of full load burn.

Natural Gas

The Vertically Integrated Utilities consumed approximately 113 billion cubic feet of natural gas during 2020 for generating power. This represents a decrease of 3.33% from 2019. Several of AEP’s natural gas-fired power plants are connected to at least two pipelines which allow greater access to competitive supplies and improve delivery reliability. A portfolio of term, monthly and daily supply and transportation agreements provide natural gas requirements for each plant, as appropriate. AEP’s natural gas supply transactions are entered into on a competitive basis and based on market prices.

The following table shows the amount of natural gas delivered to the Vertically Integrated Utilities’ plants during the past three years and the average delivered price of natural gas purchased by the Vertically Integrated Utilities.
 202020192018
Total natural gas delivered to the plants (in billions cubic feet)113.1 117.0 111.6 
Average delivered price per MMBtu of purchased natural gas$2.14 $2.64 $3.26 

Nuclear

I&M has made commitments to meet the current nuclear fuel requirements of the Cook Plant.  I&M has made and will make purchases of uranium in various forms in the spot, short-term and mid-term markets.  I&M also continues to finance its nuclear fuel through leasing.

For purposes of the storage of high-level radioactive waste in the form of SNF, I&M completed modifications to its SNF storage pool in the early 1990’s.  I&M entered into an agreement to provide for onsite dry cask storage of SNF to permit normal operations to continue.  I&M is scheduled to conduct further dry cask loading and storage projects on an ongoing periodic basis.  The year of expiration of each NRC Operating License is 2034 for Unit 1 and 2037 for Unit 2.

Nuclear Waste and Decommissioning

As the owner of the Cook Plant, I&M has a significant future financial commitment to dispose of SNF and decommission and decontaminate the plant safely.  The cost to decommission a nuclear plant is affected by NRC regulations and the SNF disposal program.  The most recent decommissioning cost study was completed in 2018.  The estimated cost of decommissioning and disposal of low-level radioactive waste for the Cook Plant was $2 billion in 2018 non-discounted dollars, with additional ongoing estimated costs of $6 million per year for post decommissioning storage of SNF and an eventual estimated cost of $37 million for the subsequent decommissioning of the spent fuel storage facility, also in 2018 non-discounted dollars. As of December 31, 2020 and 2019, the total decommissioning trust fund balance for the Cook Plant was approximately $3 billion and $2.7
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billion, respectively. The balance of funds available to eventually decommission Cook Plant will differ based on contributions and investment returns.  The ultimate cost of retiring the Cook Plant may be materially different from estimates and funding targets as a result of the:

Escalation of various cost elements (including, but not limited to, general inflation and the cost of energy).
Further development of regulatory requirements governing decommissioning.
Technology available at the time of decommissioning differing significantly from that assumed in studies.
Availability of nuclear waste disposal facilities.
Availability of a United States Department of Energy facility for permanent storage of SNF.

Accordingly, management is unable to provide assurance that the ultimate cost of decommissioning the Cook Plant will not be significantly different than current projections.  AEP will seek recovery from customers through regulated rates if actual decommissioning costs exceed projections.  See the “Nuclear Contingencies” section of Note 6 - Commitments, Guarantees and Contingencies included in the 2020 Annual Report for additional information with respect to nuclear waste and decommissioning.

Low-Level Radioactive Waste

The Low-Level Waste Policy Act of 1980 mandates that the responsibility for the disposal of low-level radioactive waste rests with the individual states.  Low-level radioactive waste consists largely of ordinary refuse and other items that have come in contact with radioactive materials.  Michigan does not currently have a disposal site for such waste available.  I&M cannot predict when such a site may be available. However, the states of Utah and Texas have licensed low-level radioactive waste disposal sites which currently accept low-level radioactive waste from Michigan waste generators.  There is currently no set date limiting I&M’s access to either of these facilities.  The Cook Plant has a facility onsite designed specifically for the storage of low-level radioactive waste.  In the event that low-level radioactive waste disposal facility access becomes unavailable, it can be stored onsite at this facility.

Counterparty Risk Management

The Vertically Integrated Utilities segment also sells power and enters into related energy transactions with wholesale customers and other market participants. As a result, counterparties and exchanges may require cash or cash related instruments to be deposited on transactions as margin against open positions.  As of December 31, 2020, counterparties posted approximately $13 million in cash, cash equivalents or letters of credit with AEPSC for the benefit of AEP’s public utility subsidiaries (while, as of that date, AEP’s public utility subsidiaries posted approximately $19 million with counterparties and exchanges).  Since open trading contracts are valued based on market prices of various commodities, exposures change daily.  See the “Quantitative and Qualitative Disclosures About Market Risk” section of Management’s Discussion and Analysis of Financial Condition and Results of Operations included in the 2020 Annual Report for additional information.

Certain Power Agreements

I&M

The UPA between AEGCo and I&M, dated March 31, 1982 (the I&M Power Agreement), provides for the sale by AEGCo to I&M of all the capacity (and the energy associated therewith) available to AEGCo at the Rockport Plant.  Whether or not power is available from AEGCo, I&M is obligated to pay a demand charge for the right to receive such power (and an energy charge for any associated energy taken by I&M).  The I&M Power Agreement will continue in effect until the debt obligations of AEGCo secured by the Rockport Plant have been satisfied and discharged (currently expected to be December 2028).


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Pursuant to an assignment between I&M and KPCo, and a UPA between AEGCo and KPCo, AEGCo sells KPCo 30% of the capacity (and the energy associated therewith) available to AEGCo from both units of the Rockport Plant.  KPCo has agreed to pay to AEGCo the amounts that I&M would have paid AEGCo under the terms of the UPA between AEGCo and I&M for such entitlement.  The KPCo UPA expires in December 2022.

OVEC

AEP and several nonaffiliated utility companies jointly own OVEC.  The aggregate equity participation of AEP in OVEC is 43.47%.  Parent owns 39.17% and OPCo owns 4.3%.  Under the Inter-Company Power Agreement (ICPA), which defines the rights of the owners and sets the power participation ratio of each, the sponsoring companies are entitled to receive and are obligated to pay for all OVEC capacity (approximately 2,400 MWs) in proportion to their respective power participation ratios.  The aggregate power participation ratio of APCo, I&M and OPCo is 43.47%.  The ICPA terminates in June 2040.  The proceeds from charges by OVEC to sponsoring companies under the ICPA based on their power participation ratios are designed to be sufficient for OVEC to meet its operating expenses and fixed costs.  OVEC’s Board of Directors, as elected by AEP and nonaffiliated owners, has authorized environmental investments related to their ownership interests, with resulting expenses (including for related debt and interest thereon) included in charges under the ICPA. OVEC financed capital expenditures totaling $1.3 billion in connection with flue gas desulfurization projects and the associated scrubber waste disposal landfills at its two generation plants through debt issuances, including tax-advantaged debt issuances.  Both OVEC generation plants are operating with the new environmental controls in-service.  See Note 17 - Variable Interest Entities and Equity Method Investments for additional information.

ELECTRIC DELIVERY

General

Other than AEGCo, AEP’s vertically integrated public utility subsidiaries own and operate transmission and distribution lines and other facilities to deliver electric power.  See Item 2 – Properties for more information regarding the transmission and distribution lines.  Most of the transmission and distribution services are sold to retail customers of AEP’s vertically integrated public utility subsidiaries in their service territories.  These sales are made at rates approved by the state utility commissions of the states in which they operate, and in some instances, approved by the FERC.  See Item 1. Business – Vertically Integrated Utilities – Regulation – Rates.  The FERC regulates and approves the rates for both wholesale transmission transactions and wholesale generation contracts.  The use and the recovery of costs associated with the transmission assets of the AEP vertically integrated public utility subsidiaries are subject to the rules, principles, protocols and agreements in place with PJM and SPP, and as approved by the FERC. See Item 1. Business – Vertically Integrated Utilities – Regulation – FERC.  As discussed below, some transmission services also are separately sold to nonaffiliated companies.

Other than AEGCo, AEP’s vertically integrated public utility subsidiaries hold franchises or other rights to provide electric service in various municipalities and regions in their service areas.  In some cases, these franchises provide the utility with the exclusive right to provide electric service within a specific territory.  These franchises have varying provisions and expiration dates.  In general, the operating companies consider their franchises to be adequate for the conduct of their business.  For a discussion of competition in the sale of power, see Item 1. Business – Vertically Integrated Utilities – Competition.

Transmission Agreement

APCo, I&M, KGPCo, KPCo and WPCo own and operate transmission facilities that are used to provide transmission service under the PJM OATT and are parties to the TA.  OPCo, which is a subsidiary in AEP’s Transmission and Distribution Utilities segment that provides transmission service under the PJM OATT, is also a party to the TA.  The TA defines how the parties to the agreement share the revenues associated with their transmission facilities and the costs of transmission service provided by PJM.  The TA has been approved by the FERC.
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Transmission Coordination Agreement and Open Access Transmission Tariff

PSO, SWEPCo and AEPSC are parties to the TCA.  Under the TCA, a coordinating committee is charged with the responsibility of: (a) overseeing the coordinated planning of the transmission facilities of the parties to the agreement, including the performance of transmission planning studies, (b) the interaction of such subsidiaries with independent system operators and other regional bodies interested in transmission planning and (c) compliance with the terms of the OATT filed with the FERC and the rules of the FERC relating to such tariff.  Pursuant to the TCA, AEPSC has responsibility for monitoring the reliability of their transmission systems and administering the OATT on behalf of the other parties to the agreement.  The TCA also provides for the allocation among the parties of revenues collected for transmission and ancillary services provided under the OATT.  These allocations have been determined by the FERC-approved OATT for the SPP.

Regional Transmission Organizations

AEGCo, APCo, I&M, KGPCo, KPCo and WPCo are members of PJM, and PSO and SWEPCo are members of SPP (both FERC-approved RTOs).  RTOs operate, plan and control utility transmission assets in a manner designed to provide open access to such assets in a way that prevents discrimination between participants owning transmission assets and those that do not.

REGULATION

General

AEP’s vertically integrated public utility subsidiaries’ retail rates and certain other matters are subject to traditional cost-based regulation by the state utility commissions.  AEP’s vertically integrated public utility subsidiaries are also subject to regulation by the FERC under the Federal Power Act with respect to wholesale power and transmission service transactions.  I&M is subject to regulation by the NRC under the Atomic Energy Act of 1954, as amended, with respect to the operation of the Cook Plant.  AEP and its vertically integrated public utility subsidiaries are also subject to the regulatory provisions of, much of the Energy Policy Act of 2005, which is administered by the FERC.

Rates

Historically, state utility commissions have established electric service rates on a cost-of-service basis, which is designed to allow a utility an opportunity to recover its cost of providing service and to earn a reasonable return on its investment used in providing that service.  A utility’s cost-of-service generally reflects its operating expenses, including operation and maintenance expense, depreciation expense and taxes.  State utility commissions periodically adjust rates pursuant to a review of: (a) a utility’s adjusted revenues and expenses during a defined test period and (b) such utility’s level of investment.  Absent a legal limitation, such as a law limiting the frequency of rate changes or capping rates for a period of time, a state utility commission can review and change rates on its own initiative.  Some states may initiate reviews at the request of a utility, customer, governmental or other representative of a group of customers.  Such parties may, however, agree with one another not to request reviews of or changes to rates for a specified period of time.

Public utilities have traditionally financed capital investments until the new asset is placed in-service.  Provided the asset was found to be a prudent investment, it was then added to rate base and entitled to a return through rate recovery.  Given long lead times in construction, the high costs of plant and equipment and volatile capital markets, management actively pursues strategies to accelerate rate recognition of investments and cash flow.  AEP representatives continue to engage state commissioners and legislators on alternative rate-making options to reduce regulatory lag and enhance certainty in the process.  These options include pre-approvals, a return on construction work in progress, rider/trackers, formula rates and the inclusion of future test-year projections into rates.

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The rates of AEP’s vertically integrated public utility subsidiaries are generally based on the cost of providing traditional bundled electric service (i.e., generation, transmission and distribution service).  Historically, the state regulatory frameworks in the service area of the AEP vertically integrated public utility subsidiaries reflected specified fuel costs as part of bundled (or, more recently, unbundled) rates or incorporated fuel adjustment clauses in a utility’s rates and tariffs.  Fuel adjustment clauses permit periodic adjustments to fuel cost recovery from customers and therefore provide protection against exposure to fuel cost changes.

The following state-by-state analysis summarizes the regulatory environment of certain major jurisdictions in which AEP’s vertically integrated public utility subsidiaries operate.  Several public utility subsidiaries operate in more than one jurisdiction.  See Note 4 - Rate Matters included in the 2020 Annual Report for more information regarding pending rate matters.

Indiana

I&M provides retail electric service in Indiana at bundled rates approved by the IURC, with rates set on a cost-of-service basis.  Indiana provides for timely fuel and purchased power cost recovery through a fuel cost recovery mechanism.

Oklahoma

PSO provides retail electric service in Oklahoma at bundled rates approved by the OCC.  PSO’s rates are set on a cost-of-service basis.  Fuel and purchased energy costs are recovered or refunded by applying fuel adjustment and other factors to retail kilowatt-hour sales.

Virginia

APCo currently provides retail electric service in Virginia at unbundled generation and distribution rates approved by the Virginia SCC.  Virginia generally allows for timely recovery of fuel costs through a FAC.  In addition to base rates and fuel cost recovery, APCo is permitted to recover a variety of costs through rate adjustment clauses including transmission services provided at OATT rates based on rates established by the FERC.

West Virginia

APCo and WPCo provide retail electric service at bundled rates approved by the WVPSC, with rates set on a combined cost-of-service basis.  West Virginia generally allows for timely recovery of fuel costs through the ENEC which trues-up to actual expenses.

FERC

The FERC regulates rates for interstate power sales at wholesale, transmission of electric power, accounting and other matters, including construction and operation of hydroelectric projects.  The FERC regulations require AEP’s vertically integrated public utility subsidiaries to provide open access transmission service at FERC-approved rates, and AEP has approved cost-based formula transmission rates on file at the FERC.  The FERC also regulates unbundled transmission service to retail customers.  In addition, the FERC regulates the sale of power for resale in interstate commerce by: (a) approving contracts for wholesale sales to municipal and cooperative utilities and (b) granting authority to public utilities to sell power at wholesale at market-based rates upon a showing that the seller lacks the ability to improperly influence market prices.  AEP’s vertically integrated public utility subsidiaries have market-based rate authority from the FERC, under which much of their wholesale marketing activity takes place.  The FERC requires each public utility that owns or controls interstate transmission facilities, directly or through an RTO, to file an open access network and point-to-point transmission tariff that offers services comparable to the utility’s own uses of its transmission system.  The FERC also requires all transmitting utilities, directly or through an RTO, to establish an Open Access Same-time Information System, which electronically posts transmission information such as available capacity and prices, and requires utilities to comply with Standards of Conduct that prohibit utilities’ transmission employees from providing non-public transmission information to the utility’s marketing employees. Additionally, the vertically integrated public utility subsidiaries are subject to reliability standards promulgated by the NERC, with the approval of the FERC.
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The FERC oversees RTOs, entities created to operate, plan and control utility transmission assets.  AEGCo, APCo, I&M, KGPCo, KPCo and WPCo are members of PJM.  PSO and SWEPCo are members of SPP.

The FERC has jurisdiction over the issuances of securities of most of AEP’s public utility subsidiaries, the acquisition of securities of utilities, the acquisition or sale of certain utility assets and mergers with another electric utility or holding company.  In addition, both the FERC and state regulators are permitted to review the books and records of any company within a holding company system.

COMPETITION

Other than AEGCo, AEP’s vertically integrated public utility subsidiaries generate, transmit and distribute electricity to retail customers of AEP’s vertically integrated public utility subsidiaries in their service territories.  These sales are made at rates approved by the state utility commissions of the states in which they operate, and in some instances, approved by the FERC, and are not subject to competition from other vertically integrated public utilities.  Other than AEGCo, AEP’s vertically integrated public utility subsidiaries hold franchises or other rights that effectively grant the exclusive ability to provide electric service in various municipalities and regions in their service areas.  

AEP’s vertically integrated public utility subsidiaries compete with self-generation and with distributors of other energy sources, such as natural gas, fuel oil, renewables and coal, within their service areas.  The primary factors in such competition are price, reliability of service and the capability of customers to utilize alternative sources of energy other than electric power. With respect to competing generators and self-generation, the public utility subsidiaries of AEP believe that they currently maintain a competitive position. 

Changes in regulatory policies and advances in newer technologies for batteries or energy storage, fuel cells, microturbines, wind turbines and photovoltaic solar cells are reducing costs of new technology to levels that are making them competitive with some central station electricity production.  The costs of photovoltaic solar cells in particular have continued to become increasingly competitive. The ability to maintain relatively low cost, efficient and reliable operations and to provide cost-effective programs and services to customers are significant determinants of AEP’s competitiveness.

SEASONALITY

The consumption of electric power is generally seasonal.  In many parts of the country, demand for power peaks during the hot summer months, with market prices also peaking at that time.  In other areas, power demand peaks during the winter.  The pattern of this fluctuation may change due to the nature and location of AEP’s facilities and the terms of power sale contracts into which AEP enters.  In addition, AEP has historically sold less power, and consequently earned less income, when weather conditions are milder. Unusually mild weather in the future could diminish AEP’s results of operations. Conversely, unusually extreme weather conditions could increase AEP’s results of operations.

TRANSMISSION AND DISTRIBUTION UTILITIES

GENERAL

This segment consists of the transmission and distribution of electricity for sale to retail and wholesale customers through assets owned and operated by AEP Texas and OPCo. OPCo is engaged in the transmission and distribution of electric power to approximately 1,507,000 retail customers in Ohio.  OPCo purchases energy and capacity to serve standard service offer customers and provides transmission and distribution services for all connected load. AEP Texas is engaged in the transmission and distribution of electric power to approximately 1,068,000 retail customers through REPs in west, central and southern Texas.

AEP’s transmission and distribution utility subsidiaries own and operate transmission and distribution lines and other facilities to deliver electric power.  See Item 2 – Properties, for more information regarding the transmission
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and distribution lines.  Transmission and distribution services are sold to retail customers of AEP’s transmission and distribution utility subsidiaries in their service territories.  These sales are made at rates approved by the PUCT for AEP Texas and by the PUCO and the FERC for OPCo.  The FERC regulates and approves the rates for wholesale transmission transactions.  As discussed below, some transmission services also are separately sold to nonaffiliated companies.

AEP’s transmission and distribution utility subsidiaries hold franchises or other rights to provide electric service in various municipalities and regions in their service areas.  In some cases, these franchises provide the utility with the exclusive right to provide electric service.  These franchises have varying provisions and expiration dates.  In general, the operating companies consider their franchises to be adequate for the conduct of their business.

The use and the recovery of costs associated with the transmission assets of the AEP transmission and distribution utility subsidiaries are subject to the rules, protocols and agreements in place with PJM and ERCOT, and as approved by the FERC.  In addition to providing transmission services in connection with power sales in their service areas, AEP’s transmission and distribution utility subsidiaries also provide transmission services for nonaffiliated companies through RTOs.

Transmission Agreement

OPCo owns and operates transmission facilities that are used to provide transmission service under the PJM OATT; OPCo is a party to the TA with other utility subsidiary affiliates. The TA defines how the parties to the agreement share the revenues associated with their transmission facilities and the costs of transmission service provided by PJM. The TA has been approved by the FERC.

Regional Transmission Organizations

OPCo is a member of PJM, a FERC-approved RTO.  RTOs operate, plan and control utility transmission assets to provide open access to such assets in a way that prevents discrimination between participants owning transmission assets and those that do not.  AEP Texas is a member of ERCOT.

REGULATION

OPCo provides distribution and transmission services to retail customers within its service territory at cost-based rates approved by the PUCO or by the FERC.  AEP Texas provides transmission and distribution service on a cost-of-service basis at rates approved by the PUCT and wholesale transmission service under tariffs approved by the FERC consistent with PUCT rules.  Transmission and distribution rates are established on a cost-of-service basis, which is designed to allow a utility an opportunity to recover its cost of providing service and to earn a reasonable return on its investment used in providing that service.  The cost-of-service generally reflects operating expenses, including operation and maintenance expense, depreciation expense and taxes.  Utility commissions periodically adjust rates pursuant to a review of: (a) a utility’s adjusted revenues and expenses during a defined test period and (b) such utility’s level of investment.

FERC

The FERC regulates rates for transmission of electric power, accounting and other matters.  The FERC regulations require AEP to provide open access transmission service at FERC-approved rates, and it has approved cost-based formula transmission rates on file at the FERC.  The FERC also regulates unbundled transmission service to retail customers.  The FERC requires each public utility that owns or controls interstate transmission facilities to, directly or through an RTO, file an open access network and point-to-point transmission tariff that offers services comparable to the utility’s own uses of its transmission system.  The FERC also requires all transmitting utilities, directly or through an RTO, to establish an Open Access Same-time Information System, which electronically posts transmission information such as available capacity and prices, and requires utilities to comply with Standards of Conduct that prohibit utilities’ transmission employees from providing non-public transmission information to the utility’s marketing employees. In addition, both the FERC and state regulators are permitted to review the books
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and records of any company within a holding company system. Additionally, the transmission and distribution utility subsidiaries are subject to reliability standards as set forth by the NERC, with the approval of the FERC.

SEASONALITY

The delivery of electric power is generally seasonal.  In many parts of the country, demand for power peaks during the hot summer months.  In other areas, power demand peaks during the winter months.  The pattern of this fluctuation may change due to the nature and location of AEP’s transmission and distribution facilities.  In addition, AEP transmission and distribution has historically delivered less power, and consequently earned less income, when weather conditions are milder.  In Texas, and to a lesser extent, in Ohio, where there is residential decoupling, unusually mild weather in the future could diminish AEP’s results of operations.  Conversely, unusually extreme weather conditions could increase AEP’s results of operations.

AEP TRANSMISSION HOLDCO

GENERAL

AEPTHCo is a holding company for (a) AEPTCo, which is the direct holding company for the State Transcos and (b) AEP’s Transmission Joint Ventures.

AEPTCo

AEPTCo wholly owns the State Transcos which are independent of, but respectively overlay, the following AEP electric utility operating companies: APCo, I&M, KPCo, OPCo, PSO, SWEPCo, and WPCo. The State Transcos develop, own, operate, and maintain their respective transmission assets. Assets of the State Transcos interconnect to transmission facilities owned by the aforementioned operating companies and nonaffiliated transmission owners within the footprints of PJM, MISO and SPP. APTCo, IMTCo, KTCo, OHTCo, and WVTCo are located within PJM. IMTCo also owns portions of the Greentown station assets located in MISO. OKTCo and SWTCo are located within SPP.

IMTCo, KTCo, OHTCo, OKTCo, and WVTCo own and operate transmission assets in their respective jurisdictions.  The Virginia SCC and WVPSC granted consent for APCo and APTCo to enter into a joint license agreement that will support APTCo investment in the state of Tennessee. SWTCo does not currently own or operate transmission assets.

The State Transcos are regulated for rate-making purposes exclusively by the FERC and earn revenues through tariff rates charged for the use of their electric transmission systems.  The State Transcos establish transmission rates each year through formula rate filings with the FERC.  The rate filings calculate the revenue requirement needed to cover the costs of operation and debt service and to earn an allowed ROE.  These rates are then included in an OATT for PJM, MISO and SPP.

The State Transcos own, operate, maintain and invest in transmission infrastructure in order to maintain and enhance system integrity and grid reliability, grid security, safety, reduce transmission constraints and facilitate interconnections of new generating resources and new wholesale customers, as well as enhance competitive wholesale electricity markets. A key part of AEP’s business is replacing and upgrading transmission facilities, assets and components of the existing AEP System as needed to maintain reliability.

The State Transcos provide the capability to build, replace and upgrade existing facilities. As of December 31, 2020, the State Transcos had $9.9 billion of transmission and other assets in-service with plans to construct approximately $4.2 billion of additional transmission assets through 2023. Additional investment in transmission infrastructure is needed within PJM and SPP to maintain the required level of grid reliability, resiliency, security and efficiency and to address an aging transmission infrastructure. Additional transmission facilities will be needed based on changes in generating resources, such as wind or solar projects, generation additions or retirements, and additional new customer interconnections.  The State Transcos will continue their investment to enhance physical and cyber security of assets, and are also investing in improving the telecommunication network that supports the operation and control of the grid.
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AEPTHCO JOINT VENTURE INITIATIVES

AEP has established joint ventures with other electric utility companies for the purpose of developing, building, and owning transmission assets that seek to improve reliability and market efficiency and provide transmission access to remote generation sources in North America (Transmission Joint Ventures).

The Transmission Joint Ventures currently include:
Joint Venture NameLocationProjected or Actual Completion DateOwners
(Ownership %)
Total Estimated/Actual Project Costs at CompletionApproved Return on Equity
 (in millions)
ETTTexas(a)Berkshire Hathaway$3,500.0 (a)9.6 %
 (ERCOT)  Energy (50%)    
   AEP (50%)    
Prairie WindKansas2014Evergy, Inc. (50%) 158.0 12.8 %
Berkshire Hathaway Energy (25%)
   AEP (25%)      
PioneerIndiana2018Duke Energy (50%) 191.0 10.52 %(b)
    AEP (50%)     
TransourceMissouri2016Evergy, Inc. 310.5 11.1 %(c)
Missouri   (13.5%) (d)    
    AEP (86.5%) (d)     
TransourceWest2019Evergy, Inc.84.0 10.5 %
West VirginiaVirginia(13.5%) (d) 
AEP (86.5%) (d) 
TransourceMaryland2023Evergy, Inc.20.9 (e)10.4 %
Maryland(13.5%) (d)
AEP (86.5%) (d)
TransourcePennsylvania2023Evergy, Inc.248.6 (e)10.4 %
Pennsylvania(13.5%) (d)
AEP (86.5%) (d)
TransourceOklahoma2026Evergy, Inc.112.6(f)10.3 %
Oklahoma (13.5%(d)
 AEP (86.5%) (d)

(a)ETT is undertaking multiple projects and the completion dates will vary for those projects. ETT’s investment in completed and active projects in ERCOT is expected to be $3.5 billion.  Future projects will be evaluated on a case-by-case basis.
(b)In May 2020, Pioneer received FERC approval authorizing an ROE of 10.02% (10.52% inclusive of the RTO incentive adder of 0.5%).
(c)The ROE represents the weighted-average approved ROE based on the costs of two projects developed by Transource Missouri; the $64 million Iatan-Nashua project (10.3%) and the $247 million Sibley-Nebraska City project (11.3%).
(d)AEP owns 86.5% of Transource Missouri, Transource West Virginia, Transource Maryland, Transource Pennsylvania and Transource –Sooner-Wekiwa through its ownership interest in Transource Energy, LLC (Transource).  Transource is a joint venture with AEPTHCo and Evergy, Inc. formed to pursue competitive transmission projects.  AEPTHCo and Evergy, Inc. own 86.5% and 13.5% of Transource, respectively.
(e)In August 2016, Transource Maryland and Transource Pennsylvania received approval from the PJM Interconnection Board to construct portions of a transmission project located in both Maryland and Pennsylvania. The project is expected to go in-service in 2023. Project costs are in 2020 dollars.
(f)In 2016, Transource Kansas received approval from the FERC authorizing an ROE of 9.8% (10.3% inclusive of the RTO incentive adder of 0.5%) for future competitive transmission projects in SPP. In October 2020, Transource was awarded the Sooner-Wekiwa project by SPP and the project was assigned to Transource Kansas. In November 2020, Transource Kansas was renamed Transource Oklahoma. The project is expected to go in-service in 2026.

Transource Missouri, Transource West Virginia, Transource Maryland, Transource Pennsylvania and Transource Oklahoma are consolidated joint ventures by AEP.  All other joint ventures in the table above are not consolidated by AEP. AEP’s joint ventures do not have employees.  Business services for the joint ventures are provided by AEPSC and other AEP subsidiaries and the joint venture partners. During 2020, approximately 514 AEPSC employees and 271 operating company employees provided service to one or more joint ventures.

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REGULATION

The State Transcos and the Transmission Joint Ventures located outside of ERCOT establish transmission rates annually through forward-looking formula rate filings with the FERC pursuant to FERC-approved implementation protocols.  The protocols include a transparent, formal review process to ensure the updated transmission rates are prudently-incurred and reasonably calculated. The IMTCo-owned Greentown station assets acquired from Duke Energy Indiana, LLC in December 2018 are located in MISO. IMTCo utilizes a historic cost recovery model to recover MISO assets.

The State Transcos’ and the Transmission Joint Ventures’ (where applicable) rates are included in the respective OATT for PJM and SPP.  An OATT is the FERC rate schedule that provides the terms and conditions for transmission and related services on a transmission provider’s transmission system.  The FERC requires transmission providers such as PJM and SPP to offer transmission service to all eligible customers (for example, load-serving entities, power marketers, generators and customers) on a non-discriminatory basis.

The FERC-approved formula rates establish the annual transmission revenue requirement (ATRR) and transmission service rates for transmission owners in annual rate base filings with the FERC.  The formula rates establish rates for a one-year period based on the current projects in-service and proposed projects for a defined timeframe.  The formula rates also include a true-up calculation for the previous year’s billings, allowing for over/under-recovery of the transmission owner’s ATRR.  PJM and SPP pay the transmission owners their ATRR for use of their facilities and bill transmission customers taking service under the PJM and SPP OATTs, based on the terms and conditions in the respective OATT for the service taken. Additionally, the State Transcos are subject to reliability standards promulgated by the NERC, with the approval of the FERC.

Management continues to monitor the FERC’s 2019 Notice of Inquiry regarding base ROE policy, the FERC’s 2020 Notice of Proposed Rulemaking regarding transmission incentives policy, and various other matters pending before the FERC with the potential to affect the transmission ROE methodology.

In the second quarter of 2019, the FERC approved settlement agreements establishing base ROEs of 9.85% (10.35% inclusive of RTO incentive adder of 0.5%) and 10% (10.5% inclusive of RTO incentive adder of 0.5%) for AEP’s PJM and SPP transmission-owning subsidiaries, respectively. In the second quarter of 2020, FERC Order 569A determined the base ROE for MISO’s transmission owning members, including AEP’s MISO transmission-owning subsidiaries, should be 10.02% (10.52% inclusive of the RTO incentive adder of 0.5%).

If the FERC makes any changes to its ROE and incentive policies, they would be applied, as applicable, to AEP’s PJM, SPP and MISO transmission owning subsidiaries on a prospective basis, and could affect future net income and cash flows and impact financial condition.

In the annual rate base filings described above, the State Transcos in aggregate filed rate base totals of $7.0 billion, $5.9 billion and $4.6 billion for 2020, 2019 and 2018, respectively.  The total filed transmission revenue requirements, including prior year over/under-recovery of revenue and associated carrying charges were $1.2 billion, $992 million and $829 million for 2020, 2019, and 2018, respectively.

The rates of ETT, which is located in ERCOT, are determined by the PUCT.  ETT sets its rates through a combination of base rate cases and interim Transmission Cost of Services (TCOS) filings.  ETT may file interim TCOS filings semi-annually to update its rates to reflect changes in its net invested capital.

The Transmission Joint Ventures have approved ROEs ranging from 9.6% to 12.8% based on equity capital structures ranging from 40% to 60%.

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GENERATION & MARKETING

GENERAL

The AEP Generation & Marketing segment subsidiaries consist of a wholesale energy trading and marketing business, a retail supply and energy management business and competitive generating assets.  

AEP Energy Supply, LLC is a holding company with several divisions, including AEP Renewables and AEP OnSite Partners.

AEP Renewables develops, owns and operates utility scale renewable projects backed with long-term contracts with creditworthy counterparties throughout the United States.  AEP Renewables works directly with stakeholders to ensure that customers have clean, sustainable renewable energy to meet their environmental goals.  As of December 31, 2020, AEP Renewables owned projects operating in 11 states, including approximately 1,307 MWs of installed wind capacity and 90 MWs of installed solar capacity.  In October 2019, AEP Renewables entered into an agreement to construct Flat Ridge 3, a wind farm in Kansas.  The 128 MW facility is expected to reach commercial operation by May 2021. In November 2020, AEP Renewables signed a Purchase and Sale Agreement to acquire 75% of the Dry Lake Solar Project, a 100 MW solar facility in southern Nevada. This facility is expected to be in-service in the second quarter of 2021.

AEP OnSite Partners works directly with wholesale and large retail customers to provide tailored solutions to reduce their energy costs based upon market knowledge, innovative applications of technology and deal structuring capabilities.  AEP OnSite Partners targets opportunities in distributed solar, combined heat and power, energy storage, waste heat recovery, energy efficiency, peaking generation and other energy solutions that create value for customers.  AEP OnSite Partners pursues and develops behind the meter projects with creditworthy customers.  As of December 31, 2020, AEP OnSite Partners owned projects located in 21 states, including approximately 152 MWs of installed solar capacity, and approximately 9 MWs of solar projects under construction.

With respect to the wholesale energy trading and marketing business, AEP Generation & Marketing segment subsidiaries enter into short-term and long-term transactions to buy or sell capacity, energy and ancillary services in ERCOT, SPP, MISO and PJM.  These subsidiaries sell power into the market and engage in power, natural gas and emissions allowances risk management and trading activities.  These activities primarily involve the purchase-and-sale of electricity (and to a lesser extent, natural gas and emissions allowances) under forward contracts at fixed and variable prices.  These contracts include physical transactions, exchange-traded futures, and to a lesser extent, OTC swaps and options.  The majority of forward contracts are typically settled by entering into offsetting contracts.  These transactions are executed with numerous counterparties or on exchanges.

With respect to the retail supply and energy management business, AEP Energy is a retail energy supplier that supplies electricity and/or natural gas to residential, commercial, and industrial customers.  AEP Energy provides various energy solutions in Illinois, Pennsylvania, Delaware, Maryland, New Jersey, Ohio and Washington, D.C.  AEP Energy had approximately 510,000 customer accounts as of December 31, 2020.

The primary fossil generation subsidiary in the Generation & Marketing segment is AGR.  As of December 31, 2020, AGR owns 643 MWs of generating capacity, almost all of which is operated by Buckeye Power, a nonaffiliated electric cooperative. Other subsidiaries in this segment own or have the right to receive power from additional generation assets. See Item 2 – Properties for more information regarding the generation assets of the Generation & Marketing segment. AGR is a competitive generation subsidiary.

REGULATION

AGR is a public utility under the Federal Power Act, and is subject to the FERC’s exclusive rate-making jurisdiction over wholesale sales of electricity and the transmission of electricity in interstate commerce. Under the Federal Power Act, the FERC has the authority to grant or deny market-based rates for sales of energy, capacity and ancillary services to ensure that such sales are just and reasonable.  The FERC granted AGR market-based rate authority in December 2013.  The FERC’s jurisdiction over rate-making also includes the authority to suspend the
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market-based rates of AGR and set cost-based rates if the FERC subsequently determines that it can exercise market power, create barriers to entry or engage in abusive affiliate transactions.  Periodically, AGR is required to file a market power update to show that it continues to meet the FERC’s standards with respect to generation market power and other criteria used to evaluate whether it continues to qualify for market-based rates.  Other matters subject to the FERC jurisdiction include, but are not limited to, review of mergers, and dispositions of jurisdictional facilities and acquisitions of securities of another public utility or an existing operational generating facility.

Specific operations of AGR are also subject to the jurisdiction of various other federal, state, regional and local agencies, including federal and state environmental protection agencies.  AGR is also regulated by the PUCT for transactions inside ERCOT.  Additionally, AGR is subject to mandatory reliability standards promulgated by the NERC, with the approval of the FERC.

COMPETITION

The AEP Generation & Marketing segment subsidiaries face competition for the sale of available power, capacity and ancillary services.  The principal factors of impact are electricity and fuel prices, new market entrants, construction or retirement of generating assets by others and technological advances in power generation. Because most of AGR’s remaining generation is coal-fired, lower relative natural gas prices will favor competitors that have a higher concentration of natural gas fueled generation.  Other factors impacting competitiveness include environmental regulation, transmission congestion or transportation constraints at or near generation facilities, inoperability or inefficiencies, outages and deactivations and retirements at generation facilities.

Technology advancements, increased demand for clean energy, changing consumer behaviors, low-priced and abundant natural gas, and regulatory and public policy reforms are among the catalysts for transformation within the industry that impact competition for AEP’s Generation & Marketing segment. AGR also competes with self-generation and with distributors of other energy sources, such as natural gas, fuel oil, renewables and coal, within their service areas.  The primary factors in such competition are price, unit availability and the capability of customers to utilize sources of energy other than electric power.

Changes in regulatory policies and advances in newer technologies for batteries or energy storage, fuel cells, microturbines, wind turbines and photovoltaic solar cells are reducing costs of new technology to levels that are making them competitive with some central station electricity production.  The ability to maintain relatively low cost, efficient and reliable operations and to provide cost-effective programs and services to customers are significant determinants of AGR’s competitiveness. The costs of photovoltaic solar cells in particular have continued to become increasingly competitive.

This segment’s retail operations provide competitive electricity and natural gas in deregulated retail energy markets in six states and Washington, D.C. Each such retail choice jurisdiction establishes its own laws and regulations governing its competitive market, and public utility commission communications and utility default service pricing can affect customer participation in retail competition. Sustained low natural gas and power prices, low market volatility and maturing competitive environments can adversely affect this business.

This segment also engages in procuring and selling output from renewable generation sources under long-term contracts to creditworthy counterparties.  New sources are not acquired without first securing a long-term placement of such power.  Existing sources do not face competitive exposure.  Competitive nonaffiliated suppliers of renewable or other generation could limit opportunities for future transactions for new sources and related output contracts.

SEASONALITY

The consumption of electric power is generally seasonal.  In many parts of the country, demand for power peaks during the hot summer months, with market prices also peaking at that time.  In other areas, power demand peaks during the winter months.  The pattern of this fluctuation may change.
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Fuel Supply

The following table shows the generation sources by type, on an actual net generation (MWhs) basis, used by the Generation & Marketing segment, not including AEP Energy Partners’ offtake agreement from the Oklaunion Power Station which was retired in September 2020:
202020192018
Coal46%64%88%
Renewables54%36%12%

Coal and Consumables

AGR procures coal and consumables needed to burn the coal under a combination of purchasing arrangements including long-term and spot contracts with various producers and coal trading firms.  As contracts expire, they are replaced, as needed, with contracts at market prices. Coal and consumable inventories remain adequate to meet generation requirements.

Management believes that AGR will be able to secure and transport coal and consumables of adequate quality and in adequate quantities to operate its coal-fired unit.  AGR, through its contracts with third-party transporters, has the ability to adequately move and store coal and consumables for use in its generating facility. AGR plants consumed 1.6 million tons of coal in 2020.

The coal supplies at AGR’s plant vary from time to time depending on various factors, including, but not limited to, demand for electric power, unit outages, transportation infrastructure limitations, space limitations, plant coal consumption rates, coal quality, availability of acceptable coals, labor issues and weather conditions, which may interrupt production or deliveries. AGR aims to maintain the coal inventory of its managed plant in the range of 20 to 60 days of full load burn.  As of December 31, 2020, the coal inventory of AGR was within the target range.

Counterparty Risk Management

Counterparties and exchanges may require cash or cash related instruments to be deposited on these transactions as margin against open positions.  As of December 31, 2020, counterparties posted approximately $29 million in cash, cash equivalents or letters of credit with AEP for the benefit of AEP’s Generation & Marketing segment subsidiaries (while, as of that date, AEP’s Generation & Marketing segment subsidiaries posted approximately $122 million with counterparties and exchanges).  Since open trading contracts are valued based on market prices of various commodities, exposures change daily.  See the “Quantitative and Qualitative Disclosures About Market Risk” section of Management’s Discussion and Analysis of Financial Condition and Results of Operations included in the 2020 Annual Report for additional information.

Certain Power Agreements

As of December 31, 2020, the assets utilized in this segment included approximately 1,307 MWs of company-owned domestic wind power facilities and 101 MWs of domestic wind power from long-term purchase power agreements. Additional long term purchased power agreements have been entered into for 712 MWs of wind and 200 MWs of solar capacity which are all under construction. These agreements are all contingent on completion of construction which is expected by the end of 2022. An agreement which transferred 355 MWs of coal-fired capacity from the Oklaunion Power Station to this segment was terminated upon the closure of the facility in October.
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INFORMATION ABOUT OUR EXECUTIVE OFFICERS

The following persons are executive officers of AEP.  Their ages are given as of February 25, 2021.  The officers are appointed annually for a one-year term by the board of directors of AEP.

Nicholas K. Akins
Chairman of the Board, President and Chief Executive Officer
Age 60
Chairman of the Board since January 2014, President since January 2011 and Chief Executive Officer since November 2011.

Lisa M. Barton
Executive Vice President and Chief Operating Officer
Age 55
Executive Vice President - Utilities from January 2019 to December 2020, Executive Vice President - Transmission from August 2011 to December 2018.

Paul Chodak, III
Executive Vice President - Generation
Age 57
Executive Vice President - Utilities from January 2017 to December 2018. President and Chief Operating Officer of I&M from July 2010 to December 2016.

David M. Feinberg
Executive Vice President, General Counsel and Secretary
Age 51
Executive Vice President since January 2013.

Lana L. Hillebrand (Retired in 2020)
Executive Vice President and Chief Administrative Officer
Age 60
Chief Administrative Officer since December 2012 and Senior Vice President from December 2012 to December 2016.

Mark C. McCullough
Executive Vice President - Energy Delivery
Age 61
Executive Vice President - Transmission from January 2019 to December 2020, Executive Vice President - Generation from January 2011 to December 2018.

Charles R. Patton
Executive Vice President - External Affairs
Age 61
Executive Vice President - External Affairs since January 2017. President and Chief Operating Officer of APCo from June 2010 to December 2016.

Julia A. Sloat
Executive Vice President and Chief Financial Officer
Age 51
Senior Vice President, Treasury & Risk and Treasurer from January 2019 to December 2020. President and Chief Operating Officer of OPCo from May 2016 to December 2018.


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Brian X. Tierney
Executive Vice President - Strategy
Age 53
Executive Vice President and Chief Financial Officer from October 2009 to December 2020.

Charles E. Zebula
Executive Vice President - Energy Supply
Age 60
Executive Vice President - Energy Supply since January 2013.
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ITEM 1A.   RISK FACTORS

GENERAL RISKS OF REGULATED OPERATIONS

AEP may not be able to recover the costs of substantial planned investment in capital improvements and additions. (Applies to all Registrants)

AEP’s business plan calls for extensive investment in capital improvements and additions, including the construction of additional transmission facilities, modernizing existing infrastructure, installation of environmental upgrades and retrofits as well as other initiatives.  AEP’s public utility subsidiaries currently provide service at rates approved by one or more regulatory commissions.  If these regulatory commissions do not approve adjustments to the rates charged, affected AEP subsidiaries would not be able to recover the costs associated with their investments.  This would cause financial results to be diminished.

Regulated electric revenues and earnings are dependent on federal and state regulation that may limit AEP’s ability to recover costs and other amounts. (Applies to all Registrants)

The rates customers pay to AEP regulated utility businesses are subject to approval by the FERC and the respective state utility commissions of Arkansas, Indiana, Kentucky, Louisiana, Michigan, Ohio, Oklahoma, Tennessee, Texas, Virginia and West Virginia. In certain instances, AEP’s applicable regulated utility businesses may agree to negotiated settlements related to various rate matters that are subject to regulatory approval. AEP cannot predict the ultimate outcomes of any settlements or the actions by the FERC or the respective state commissions in establishing rates.

If regulated utility earnings exceed the returns established by the relevant commissions, retail electric rates may be subject to review and possible reduction by the commissions, which may decrease future earnings. Additionally, if regulatory bodies do not allow recovery of costs incurred in providing service on a timely basis, it could reduce future net income and cash flows and negatively impact financial condition. Similarly, if recovery or other rate relief authorized in the past is overturned or reversed on appeal, future earnings could be negatively impacted. Any regulatory action or litigation outcome that triggers a reversal of a regulatory asset or deferred cost generally results in an impairment to the balance sheet and a charge to the income statement of the company involved. See Note 4 – Rate Matters included in the 2020 Annual Report for additional information.

AEP’s transmission investment strategy and execution are dependent on federal and state regulatory policy. (Applies to all Registrants)

A significant portion of AEP’s earnings is derived from transmission investments and activities.  FERC policy currently favors the expansion and updating of the transmission infrastructure within its jurisdiction.  If the FERC were to adopt a different policy, if states were to limit or restrict such policies, or if transmission needs do not continue or develop as projected, AEP’s strategy of investing in transmission could be impacted.  Management believes AEP’s experience with transmission facilities construction and operation gives AEP an advantage over other competitors in securing authorization to install, construct and operate new transmission lines and facilities.  However, there can be no assurance that PJM, SPP, ERCOT or other RTOs will authorize new transmission projects or will award such projects to AEP.  

Certain elements of AEP’s transmission formula rates have been challenged, which could result in lowered rates and/or refunds of amounts previously collected and thus have an adverse effect on AEP’s business, financial condition, results of operations and cash flows. (Applies to all Registrants other than AEP Texas)

AEP provides transmission service under rates regulated by the FERC. The FERC has approved the cost-based formula rate templates used by AEP to calculate its respective annual revenue requirements, but it has not expressly approved the amount of actual capital and operating expenditures to be used in the formula rates. All aspects of AEP’s rates accepted or approved by the FERC, including the formula rate templates, the rates of return on the
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actual equity portion of its respective capital structures and the approved targeted capital structures, are subject to challenge by interested parties at the FERC, or by the FERC on its own initiative. In addition, interested parties may challenge the annual implementation and calculation by AEP of its projected rates and formula rate true-up pursuant to its approved formula rate templates under AEP’s formula rate implementation protocols. If a challenger can establish that any of these aspects are unjust, unreasonable, unduly discriminatory or preferential, then the FERC can make appropriate prospective adjustments to them and/or disallow any of AEP’s inclusion of those aspects in the rate setting formula.

AEP settled challenges to its SPP and PJM formula rates in proceedings at the FERC in 2019.  However, inquiries related to rates of return, as well as challenges to the formula rates of other utilities, are ongoing in other proceedings at the FERC.  The results of these proceedings could potentially negatively impact AEP in any future challenges to AEP’s formula rates.  If the FERC orders revenue reductions, including refunds, in any future cases related to its formula rates, it could reduce future net income and cash flows and impact financial condition.

End-use consumers and entities supplying electricity to end-use consumers may also attempt to influence government and/or regulators to change the rate setting methodologies that apply to AEP, particularly if rates for delivered electricity increase substantially.

AEP faces risks related to project siting, financing, construction, permitting, governmental approvals and the negotiation of project development agreements that may impede their development and operating activities. (Applies to all Registrants)

AEP owns, develops, constructs, manages and operates electric generation, transmission and distribution facilities. A key component of AEP's growth is its ability to construct and operate these facilities. As part of these operations AEP must periodically apply for licenses and permits from various local, state, federal and other regulatory authorities and abide by their respective conditions. Should AEP be unsuccessful in obtaining necessary licenses or permits on acceptable terms or resolving third-party challenges to such licenses or permits, should there be a delay in obtaining or renewing necessary licenses or permits or should regulatory authorities initiate any associated investigations or enforcement actions or impose related penalties or disallowances, it could reduce future net income and cash flows and impact financial condition. Any failure to negotiate successful project development agreements for new facilities with third-parties could have similar results.

Changes in technology and regulatory policies may lower the value of electric utility facilities and franchises. (Applies to all Registrants)

AEP primarily generates electricity at large central facilities and delivers that electricity to customers over its transmission and distribution facilities to customers usually situated within an exclusive franchise. This method results in economies of scale and generally lower costs than newer technologies such as fuel cells and microturbines, and distributed generation using either new or existing technology.  Other technologies, such as light emitting diodes (LEDs), increase the efficiency of electricity and, as a result, lower the demand for it.   Changes in regulatory policies and advances in batteries or energy storage, wind turbines and photovoltaic solar cells are reducing costs of new technology to levels that are making them competitive with some central station electricity production and delivery.  These developments can challenge AEP’s competitive ability to maintain relatively low cost, efficient and reliable operations, to establish fair regulatory mechanisms and to provide cost-effective programs and services to customers.  Further, in the event that alternative generation resources are mandated, subsidized or encouraged through legislation or regulation or otherwise are economically competitive and added to the available generation supply, such resources could displace a higher marginal cost generating units, which could reduce the price at which market participants sell their electricity.


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AEP may not recover costs incurred to begin construction on projects that are canceled. (Applies to all Registrants)

AEP’s business plan for the construction of new projects involves a number of risks, including construction delays, non-performance by equipment and other third-party suppliers, and increases in equipment and labor costs.  To limit the risks of these construction projects, AEP’s subsidiaries enter into equipment purchase orders and construction contracts and incur engineering and design service costs in advance of receiving necessary regulatory approvals and/or siting or environmental permits.  If any of these projects are canceled for any reason, including failure to receive necessary regulatory approvals and/or siting or environmental permits, significant cancellation penalties under the equipment purchase orders and construction contracts could occur.  In addition, if any construction work or investments have been recorded as an asset, an impairment may need to be recorded in the event the project is canceled.

AEP is exposed to nuclear generation risk. (Applies to AEP and I&M)

I&M owns the Cook Plant, which consists of two nuclear generating units for a rated capacity of 2,288 MWs, or about 7% of the generating capacity in the AEP System.  AEP and I&M are, therefore, subject to the risks of nuclear generation, which include the following:

The potential harmful effects on the environment and human health due to an adverse incident/event resulting from the operation of nuclear facilities and the storage, handling and disposal of radioactive materials such as SNF.
Limitations on the amounts and types of insurance commercially available to cover losses that might arise in connection with nuclear operations.
Uncertainties with respect to contingencies and assessment amounts triggered by a loss event (federal law requires owners of nuclear units to purchase the maximum available amount of nuclear liability insurance and potentially contribute to the coverage for losses of others).
Uncertainties with respect to the technological and financial aspects of decommissioning nuclear plants at the end of their licensed lives.

There can be no assurance that I&M’s preparations or risk mitigation measures will be adequate if these risks are triggered.

The NRC has broad authority under federal law to impose licensing and safety-related requirements for the operation of nuclear generation facilities.  In the event of non-compliance, the NRC has the authority to impose fines or shut down a unit, or both, depending upon its assessment of the severity of the situation, until compliance is achieved.  Revised safety requirements promulgated by the NRC could necessitate substantial capital expenditures at nuclear plants.  In addition, although management has no reason to anticipate a serious nuclear incident at the Cook Plant, if an incident did occur, it could harm results of operations or financial condition.  A major incident at a nuclear facility anywhere in the world could cause the NRC to limit or prohibit the operation or licensing of any domestic nuclear unit.  Moreover, a major incident at any nuclear facility in the U.S. could require AEP or I&M to make material contributory payments.

Costs associated with the operation (including fuel), maintenance and retirement of nuclear plants continue to be more significant and less predictable than costs associated with other sources of generation, in large part due to changing regulatory requirements and safety standards, availability of nuclear waste disposal facilities and experience gained in the operation of nuclear facilities.  Costs also may include replacement power, any unamortized investment at the end of the useful life of the Cook Plant (whether scheduled or premature), the carrying costs of that investment and retirement costs.  The ability to obtain adequate and timely recovery of costs associated with the Cook Plant is not assured.


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AEP subsidiaries are exposed to risks through participation in the market and transmission structures in various regional power markets that are beyond their control. (Applies to all Registrants)

Results are likely to be affected by differences in the market and transmission structures in various regional power markets.  The rules governing the various RTOs, including SPP and PJM, may also change from time to time which could affect costs or revenues.  Existing, new or changed rules of these RTOs could result in significant additional fees and increased costs to participate in those structures, including the cost of transmission facilities built by others due to changes in transmission rate design. In addition, these RTOs may assess costs resulting from improved transmission reliability, reduced transmission congestion and firm transmission rights. As members of these RTOs, AEP’s subsidiaries are subject to certain additional risks, including the allocation among existing members, of losses caused by unreimbursed defaults of other participants in these markets and resolution of complaint cases that may seek refunds of revenues previously earned by members of these markets.

AEP could be subject to higher costs and/or penalties related to mandatory reliability standards. (Applies to all Registrants)

Owners and operators of the bulk power transmission system are subject to mandatory reliability standards promulgated by the NERC and enforced by the FERC.  The standards are based on the functions that need to be performed to ensure the bulk power system operates reliably and are guided by reliability and market interface principles.  Compliance with new reliability standards may subject AEP to higher operating costs and/or increased capital expenditures.  While management expects to recover costs and expenditures from customers through regulated rates, there can be no assurance that the applicable commissions will approve full recovery in a timely manner.  If AEP were found not to be in compliance with the mandatory reliability standards, AEP could be subject to sanctions, including substantial monetary penalties, which likely would not be recoverable from customers through regulated rates.

A substantial portion of the receivables of AEP Texas is concentrated in a small number of REPs, and any delay or default in payment could adversely affect its cash flows, financial condition and results of operations. (Applies to AEP and AEP Texas)

AEP Texas collects receivables from the distribution of electricity from REPs that supply the electricity it distributes to its customers. As of December 31, 2020, AEP Texas did business with approximately 122 REPs. Adverse economic conditions, structural problems in the market served by ERCOT or financial difficulties of one or more REPs could impair the ability of these REPs to pay for these services or could cause them to delay such payments. AEP Texas depends on these REPs to remit payments on a timely basis. Applicable regulatory provisions require that customers be shifted to another REP or a provider of last resort if a REP cannot make timely payments. Applicable PUCT regulations significantly limit the extent to which AEP Texas can apply normal commercial terms or otherwise seek credit protection from firms desiring to provide retail electric service in its service territory, and AEP Texas thus remains at risk for payments related to services provided prior to the shift to another REP or the provider of last resort. In 2020, AEP Texas’ three largest REPs accounted for 46% of its operating revenue. Any delay or default in payment by REPs could adversely affect cash flows, financial condition and results of operations. If a REP were unable to meet its obligations, it could consider, among various options, restructuring under the bankruptcy laws, in which event such REP might seek to avoid honoring its obligations, and claims might be made by creditors involving payments AEP Texas had received from such REP.

Ohio House Bill 6 (HB 6), which provides for beneficial cost recovery for OPCo and for plants owned by OVEC, has come under public scrutiny. (Applies to AEP and OPCo)

In 2019, Ohio adopted and implemented HB 6 which benefits OPCo by authorizing rate recovery for certain costs including renewable energy contracts, OVEC’s coal-fired generating units and energy efficiency measures. AEP and OPCo engaged in lobbying efforts and provided testimony during the legislative process in connection with HB 6. In July 2020, an investigation led by the U.S. Attorney’s Office resulted in a federal grand jury indictment of an Ohio legislator and associates in connection with an alleged racketeering conspiracy involving the adoption of HB
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6. The outcome of the U.S. Attorney’s Office investigation and its impact on HB 6 is not known. If the provisions of HB 6 were to be eliminated, it is unclear whether new legislation addressing similar issues would be adopted. To the extent that OPCo is unable to recover the costs currently authorized by HB 6, it could reduce future net income and cash flows and impact financial condition. In addition, the impact of continued public scrutiny of HB 6 is not known, and may have an adverse impact on AEP and OPCo, including their relationship with regulatory and legislative authorities, customers and other stakeholders. AEP is a defendant in current litigation relating to HB6 and AEP or OPCo may be involved in future litigation.

RISKS RELATED TO MARKET, ECONOMIC OR FINANCIAL VOLATILITY AND OTHER RISKS

AEP’s financial condition and results of operations could continue to be adversely affected by the ongoing Coronavirus pandemic. (Applies to all Registrants)

The global 2019 novel coronavirus pandemic is an evolving situation that could lead to extended disruption of economic activity in AEP’s markets. COVID-19 could negatively affect AEP’s ability to operate its generating and transmission and distribution assets, its ability to access capital markets, and results of operations. AEP currently cannot estimate the potential impact to its financial position, results of operations and cash flows caused by COVID-19, which will depend on future developments and which are highly uncertain at this time. See Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations - Executive Overview for additional information on COVID-19.

AEP’s financial performance may be adversely affected if AEP is unable to successfully operate facilities or perform certain corporate functions. (Applies to all Registrants)

Performance is highly dependent on the successful operation of generation, transmission and/or distribution facilities.  Operating these facilities involves many risks, including:

Operator error and breakdown or failure of equipment or processes.
Operating limitations that may be imposed by environmental or other regulatory requirements.
Labor disputes.
Compliance with mandatory reliability standards, including mandatory cyber security standards.
Information technology failure that impairs AEP’s information technology infrastructure or disrupts normal business operations.
Information technology failure that affects AEP’s ability to access customer information or causes loss of confidential or proprietary data that materially and adversely affects AEP’s reputation or exposes AEP to legal claims.
Fuel or water supply interruptions caused by transportation constraints, adverse weather such as drought, non-performance by suppliers and other factors.
Catastrophic events such as fires, earthquakes, explosions, hurricanes, tornados, ice storms, terrorism (including cyber-terrorism), floods or other similar occurrences.
Fuel costs and related requirements triggered by financial stress in the coal industry.

Physical attacks or hostile cyber intrusions could severely impair operations, lead to the disclosure of confidential information and damage AEP’s reputation. (Applies to all Registrants)

AEP and its regulated utility businesses face physical security and cybersecurity risks as the owner-operators of generation, transmission and/or distribution facilities and as participants in commodities trading. AEP and its regulated utility businesses own assets deemed as critical infrastructure, the operation of which is dependent on information technology systems. Further, the computer systems that run these facilities are not completely isolated from external networks. Parties that wish to disrupt the U.S. bulk power system or AEP operations could view these computer systems, software or networks as targets for cyber-attack.  In addition, the electric utility business requires the collection of sensitive customer data, as well as confidential employee and shareholder information, which is subject to electronic theft or loss.
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A security breach of AEP or its regulated utility businesses’ physical assets or information systems, interconnected entities in RTOs, or regulators could impact the operation of the generation fleet and/or reliability of the transmission and distribution system. AEP and its regulated utility businesses could be subject to financial harm associated with theft or inappropriate release of certain types of information, including sensitive customer, vendor, employee, trading or other confidential data. A successful cyber-attack on the systems that control generation, transmission, distribution or other assets could severely disrupt business operations, preventing service to customers or collection of revenues. The breach of certain business systems could affect the ability to correctly record, process and report financial information. A major cyber incident could result in significant expenses to investigate and repair security breaches or system damage and could lead to litigation, fines, other remedial action, heightened regulatory scrutiny and damage to AEP’s reputation. In addition, the misappropriation, corruption or loss of personally identifiable information and other confidential data could lead to significant breach notification expenses and mitigation expenses such as credit monitoring.  For these reasons, a significant cyber incident could reduce future net income and cash flows and negatively impact financial condition.

If AEP is unable to access capital markets or insurance markets on reasonable terms, it could reduce future net income and cash flows and negatively impact financial condition. (Applies to all Registrants)

AEP relies on access to capital markets as a significant source of liquidity for capital requirements not satisfied by operating cash flows; AEP also relies on access to insurance markets to assist in managing its risk and liability profile. Volatility, increased interest rates and reduced liquidity in the financial markets could affect AEP’s ability to raise capital on reasonable terms to fund capital needs, including construction costs and refinancing maturing indebtedness. Certain sources of insurance and debt and equity capital have expressed increasing unwillingness to procure insurance for or to invest in companies, such as AEP, that rely on fossil fuels. If sources of capital for AEP are reduced, capital costs could increase materially. Restricted access to capital or insurance markets and/or increased borrowing costs or insurance premiums could reduce future net income and cash flows and negatively impact financial condition.

Shareholder activism could cause AEP to incur significant expense, hinder execution of AEP’s business strategy and impact AEP’s stock price. (Applies to all Registrants)

Shareholder activism, which can take many forms and arise in a variety of situations, could result in substantial costs and divert management’s and AEP’s board’s attention and resources from AEP’s business. Additionally, such shareholder activism could give rise to perceived uncertainties as to AEP’s future, adversely affect AEP’s relationships with its employees, customers or service providers and make it more difficult to attract and retain qualified personnel. Also, AEP may be required to incur significant fees and other expenses related to activist shareholder matters, including for third-party advisors. AEP’s stock price could be subject to significant fluctuation or otherwise be adversely affected by the events, risks and uncertainties of any shareholder activism.

The announced phasing out of LIBOR after 2021 may adversely affect the costs and availability of financing. (Applies to all Registrants)

A portion of the Registrants’ indebtedness bears interest at fluctuating interest rates, primarily based on the London interbank offered rate (“LIBOR”) for deposits of U.S. dollars. On July 27, 2017, the Financial Conduct Authority in the United Kingdom announced that it would phase out LIBOR as a benchmark by the end of 2021. Subsequently, on November 30, 2020, the Federal Reserve and the Financial Conduct Authority in the United Kingdom announced that LIBOR would be phased out completely by June 20, 2023 and replaced by the Secured Overnight Financing Rate ("SOFR"). While this announcement extends the transition period to June 2023, the United States Federal Reserve concurrently issued a statement advising banks to stop new U.S. dollar LIBOR issuances by the end of 2021. However, because SOFR is a broad U.S. Treasury repo financing rate that represents overnight secured funding transactions, it differs fundamentally from U.S. dollar LIBOR. In addition, the overall financial markets may be disrupted as a result of the phase-out or replacement of LIBOR. Uncertainty as to the nature of such phase-out and alternative reference rates or disruption in the financial market could cause interest rates to increase. If sources of capital for the Registrants are reduced, capital costs could increase materially. Restricted access to capital markets and/or increased borrowing costs could reduce future net income and cash flows and negatively impact financial condition and/or liquidity.
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Downgrades in AEP’s credit ratings could negatively affect its ability to access capital. (Applies to all Registrants)

The credit ratings agencies periodically review AEP’s capital structure and the quality and stability of earnings and cash flows.  Any negative ratings actions could constrain the capital available to AEP and could limit access to funding for operations.  AEP’s business is capital intensive, and AEP is dependent upon the ability to access capital at rates and on terms management determines to be attractive.  If AEP’s ability to access capital becomes significantly constrained, AEP’s interest costs will likely increase and could reduce future net income and cash flows and negatively impact financial condition.

AEP and AEPTCo have no income or cash flow apart from dividends paid or other payments due from their subsidiaries. (Applies to AEP and AEPTCo)

AEP and AEPTCo are holding companies and have no operations of their own.  Their ability to meet their financial obligations associated with their indebtedness and to pay dividends is primarily dependent on the earnings and cash flows of their operating subsidiaries, primarily their regulated utilities, and the ability of their subsidiaries to pay dividends to, or repay loans from them.  Their subsidiaries are separate and distinct legal entities that have no obligation (apart from loans from AEP or AEPTCo) to provide them with funds for their payment obligations, whether by dividends, distributions or other payments.  Payments to AEP or AEPTCo by their subsidiaries are also contingent upon their earnings and business considerations.  AEP and AEPTCo indebtedness and dividends are structurally subordinated to all subsidiary indebtedness.

AEP’s operating results may fluctuate on a seasonal or quarterly basis and with general economic and weather conditions. (Applies to all Registrants)

Electric power consumption is generally seasonal.  In many parts of the country, demand for power peaks during the hot summer months, with market prices also peaking at that time.  In other areas, power demand peaks during the winter.  As a result, overall operating results in the future may fluctuate substantially on a seasonal basis.  In addition, AEP has historically sold less power, and consequently earned less income, when weather conditions are milder.  Unusually mild weather in the future could reduce future net income and cash flows and negatively impact financial condition.  In addition, unusually extreme weather conditions could impact AEP’s results of operations in a manner that would not likely be sustainable.

Further, deteriorating economic conditions triggered by any cause, including international tariffs, generally result in reduced consumption by customers, particularly industrial customers who may curtail operations or cease production entirely, while an expanding economic environment generally results in increased revenues.  As a result, prevailing economic conditions may reduce future net income and cash flows and negatively impact financial condition.

Volatility in the securities markets, interest rates, and other factors could substantially increase defined benefit pension and other postretirement plan costs and the costs of nuclear decommissioning. (Applies to all Registrants and to AEP and I&M with respect to the costs of nuclear decommissioning)

The costs of providing pension and other postretirement benefit plans are dependent on a number of factors, such as the rates of return on plan assets, discount rates, the level of interest rates used to measure the required minimum funding levels of the plan, changes in actuarial assumptions, future government regulation, changes in life expectancy, and the frequency and amount of AEP’s required or voluntary contributions made to the plans. Changes in actuarial assumptions and differences between the assumptions and actual values, as well as a significant decline in the value of investments that fund the pension and other postretirement plans, if not offset or mitigated by a decline in plan liabilities, could increase pension and other postretirement expense, and AEP could be required from time to time to fund the pension plan with significant amounts of cash. Such cash funding obligations could have a material impact on liquidity by reducing cash flows and could negatively affect results of operations.


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Additionally, I&M holds a significant amount of assets in its nuclear decommissioning trusts to satisfy obligations to decommission its nuclear plant. The rate of return on assets held in those trusts can significantly impact both the costs of decommissioning and the funding requirements for the trusts.

AEP’s results of operations and cash flows may be negatively affected by a lack of growth or slower growth in the number of customers, or decline in customer demand. (Applies to all Registrants)

Growth in customer accounts and growth of customer usage each directly influence demand for electricity and the need for additional power generation and delivery facilities.  Customer growth and customer usage are affected by a number of factors outside the control of AEP, such as mandated energy efficiency measures, demand-side management goals, distributed generation resources and economic and demographic conditions, such as population changes, job and income growth, housing starts, new business formation and the overall level of economic activity.

Certain regulatory and legislative bodies have introduced or are considering requirements and/or incentives to further reduce energy consumption.  Additionally, technological advances or other improvements in or applications of technology could lead to declines in per capita energy consumption.  Some or all of these factors, could impact the demand for electricity.

Failure to attract and retain an appropriately qualified workforce could harm results of operations. (Applies to all Registrants)

Certain events, such as an aging workforce without appropriate replacements, mismatch of skillset or complement to future needs, or unavailability of contract resources may lead to operating challenges and increased costs.  The challenges include lack of resources, loss of knowledge and a lengthy time period associated with skill development.  In this case, costs, including costs for contractors to replace employees, productivity costs and safety costs, may rise.  Failure to hire and adequately train replacement employees, including the transfer of significant internal historical knowledge and expertise to the new employees, or the future availability and cost of contract labor may adversely affect the ability to manage and operate the business.  If AEP is unable to successfully attract and retain an appropriately qualified workforce, future net income and cash flows may be reduced.

Changes in the price of commodities, the cost of procuring fuel, emission allowances for criteria pollutants and the costs of transport may increase AEP’s cost of producing power, impacting financial performance. (Applies to all Registrants except AEP Texas, AEPTCo and OPCo)

AEP is exposed to changes in the price and availability of fuel (including the cost to procure coal and gas) and the price and availability to transport fuel.  AEP has existing contracts of varying durations for the supply of fuel, but as these contracts end or if they are not honored, AEP may not be able to purchase fuel on terms as favorable as the current contracts.  The inability to procure fuel at costs that are economical could cause AEP to retire generating capacity prior to the end of its useful life, and while AEP typically recovers expenditures for undepreciated plant balances, there can be no assurance in the future that AEP will recover such costs. Similarly, AEP is exposed to changes in the price and availability of emission allowances.  AEP uses emission allowances based on the amount of fuel used and reductions achieved through emission controls and other measures.  Based on current environmental programs remaining in effect, AEP has sufficient emission allowances to cover the majority of the projected needs for the next two years and beyond.  If the Federal EPA attempts to further reduce interstate transport, and it is acceptable by the courts, additional costs may be incurred either to acquire additional allowances or to achieve further reductions in emissions.  If AEP needs to obtain allowances, those purchases may not be on as favorable terms as those under the current environmental programs.  AEP’s risks relative to the price and availability to transport coal include the volatility of the price of diesel which is the primary fuel used in transporting coal by barge.

Prices for coal, natural gas and emission allowances have shown material swings in the past.  Changes in the cost of fuel, emission allowances or natural gas and changes in the relationship between such costs and the market prices of power could reduce future net income and cash flows and negatively impact financial condition.
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In addition, actual power prices and fuel costs will differ from those assumed in financial projections used to value trading and marketing transactions, and those differences may be material.  As a result, as those transactions are marked-to-market, they may impact future results of operations and cash flows and impact financial condition.

AEP is subject to physical and financial risks associated with climate change. (Applies to all Registrants)

Climate change creates physical and financial risk.  Physical risks from climate change may include an increase in sea level and changes in weather conditions, such as changes in precipitation and extreme weather events, such as fires.  Customers’ energy needs vary with weather conditions, primarily temperature and humidity.  For residential customers, heating and cooling represent their largest energy use.  To the extent weather conditions are affected by climate change, customers’ energy use could increase or decrease depending on the duration and magnitude of the changes.

Increased energy use due to weather changes may require AEP to invest in additional generating assets, transmission and other infrastructure to serve increased load.  Decreased energy use due to weather changes may affect financial condition through decreased revenues.  Extreme weather conditions in general require more system backup, adding to costs, and can contribute to increased system stress, including service interruptions.  Weather conditions outside of the AEP service territory could also have an impact on revenues.  AEP buys and sells electricity depending upon system needs and market opportunities.  Extreme weather conditions creating high energy demand on AEP’s own and/or other systems may raise electricity prices as AEP buys short-term energy to serve AEP’s own system, which would increase the cost of energy AEP provides to customers.

Severe weather and weather-related events impact AEP’s service territories, primarily when thunderstorms, tornadoes, hurricanes, fires, floods and snow or ice storms occur.  To the extent the frequency and intensity of extreme weather events and storms increase, AEP’s cost of providing service will increase, including the costs and the availability of procuring insurance related to such impacts, and these costs may not be recoverable.  Changes in precipitation resulting in droughts, water shortages or floods could adversely affect operations, principally the fossil fuel generating units.  A negative impact to water supplies due to long-term drought conditions or severe flooding could adversely impact AEP’s ability to provide electricity to customers, as well as increase the price they pay for energy.  AEP may not recover all costs related to mitigating these physical and financial risks.

To the extent climate change impacts a region’s economic health, it may also impact revenues.  AEP’s financial performance is tied to the health of the regional economies AEP serves.  The price of energy, as a factor in a region’s cost of living as well as an important input into the cost of goods and services, has an impact on the economic health of the communities within the AEP System.

Management cannot predict the outcome of the legal proceedings relating to AEP’s business activities. (Applies to all Registrants)

AEP is involved in legal proceedings, claims and litigation arising out of its business operations, the most significant of which are summarized in Note 6 - Commitments, Guarantees and Contingencies included in the 2020 Annual Report.  Adverse outcomes in these proceedings could require significant expenditures that could reduce future net income and cash flows and negatively impact financial condition.

Disruptions at power generation facilities owned by third-parties could interrupt the sales of transmission and distribution services. (Applies to AEP and AEP Texas)

AEP Texas transmits and distributes electric power that the REPs obtain from power generation facilities owned by third-parties. If power generation is disrupted or if power generation capacity is inadequate, sales of transmission and distribution services may be diminished or interrupted, and results of operations, financial condition and cash flows could be adversely affected.

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Management is unable to predict the course, results or impact, if any, of current or future litigation or investigations relating to the extreme winter weather in Texas in February 2021. (Applies to AEP and AEP Texas)

As a result of the February 2021 severe winter weather in Texas which caused a shortage of electric generation, ERCOT instructed AEP Texas and other Texas electric utilities to initiate power outages to avoid a sustained large-scale outage and prevent long-term damage to the electric system. At its peak, approximately 468,000 (44%) AEP Texas customers were without power.

In February 2021, a lawsuit was filed in Nueces, Texas County Court against AEP and AEP Texas alleging the failure to exercise reasonable care in maintaining and updating its generation, transmission and distribution facilities in order to prevent cold weather failures and other related negligence. The complaint seeks monetary damages among other forms of relief.

In February 2021, AEP Texas received a Civil Investigative Demand from the Office of the Attorney General of Texas requesting, among other data, information about its communications to and from ERCOT, PUCT, retail electric providers, utilities, or power generation companies, concerning power outages related to the February 2021 winter storm. The company intends to respond to the Civil Investigative Demand.

Management is unable to predict the course or outcome of these or any future litigation or investigations or their impact, if any, on future results of operations, financial condition and cash flows.

Hazards associated with high-voltage electricity transmission may result in suspension of AEP’s operations or the imposition of civil or criminal penalties. (Applies to all Registrants)

AEP operations are subject to the usual hazards associated with high-voltage electricity transmission, including explosions, fires, inclement weather, natural disasters, mechanical failure, unscheduled downtime, equipment interruptions, remediation, chemical spills, discharges or releases of toxic or hazardous substances or gases and other environmental risks. The hazards can cause personal injury and loss of life, severe damage to or destruction of property and equipment and environmental damage, and may result in suspension of operations and the imposition of civil or criminal penalties. AEP maintains property and casualty insurance, but AEP is not fully insured against all potential hazards incident to AEP’s business, such as damage to poles, towers and lines or losses caused by outages.

AEPTCo depends on its affiliates in the AEP System for a substantial portion of its revenues. (Applies to AEPTCo)

AEPTCo’s principal transmission service customers are its affiliates in the AEP System. Management expects that these affiliates will continue to be AEPTCo’s principal transmission service customers for the foreseeable future. For the year ended December 31, 2020, its affiliates were responsible for approximately 78% of the consolidated transmission revenues of AEPTCo.

Most of the real property rights on which the assets of AEPTCo are situated result from affiliate license agreements and are dependent on the terms of the underlying easements and other rights of its affiliates. (Applies to AEPTCo)

AEPTCo does not hold title to the majority of real property on which its electric transmission assets are located. Instead, under the provisions of certain affiliate contracts, it is permitted to occupy and maintain its facilities upon real property held by the respective AEP System utility affiliate that overlay its operations. The ability of AEPTCo to continue to occupy such real property is dependent upon the terms of such affiliate contracts and upon the underlying real property rights of these utility affiliates, which may be encumbered by easements, mineral rights and other similar encumbrances that may affect the use of such real property. AEP can give no assurance that (a) the
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relevant AEP System utility affiliates will continue to be affiliates of AEPTCo, (b) suitable replacement arrangements can be obtained in the event that the relevant AEP System utility affiliates are not its affiliates and (c) the underlying easements and other rights are sufficient to permit AEPTCo to operate its assets in a manner free from interruption.

RISKS RELATED TO OWNING AND OPERATING GENERATION ASSETS AND SELLING POWER

Costs of compliance with existing environmental laws are significant. (Applies to all Registrants except AEP Texas, AEPTCo and OPCo)

Operations are subject to extensive federal, state and local environmental statutes, rules and regulations relating to air quality, water quality, waste management, natural resources and health and safety.  A majority of the electricity generated by the AEP System is produced by the combustion of fossil fuels.  Emissions of nitrogen and sulfur oxides, mercury and particulates and the discharge and disposal of solid waste (including coal-combustion residuals or CCR) resulting from fossil fueled generation plants are subject to increased regulations, controls and mitigation expenses.  Compliance with these legal requirements requires AEP to commit significant capital toward environmental monitoring, installation of pollution control equipment, emission fees, disposal and permits at AEP facilities and could cause AEP to retire generating capacity prior to the end of its estimated useful life.  Costs of compliance with environmental statutes and regulations could reduce future net income and negatively impact financial condition, especially if emission, CCR waste and/or discharge obligations are tightened, more extensive operating and/or permitting requirements are imposed or additional substances become regulated.  Although AEP typically recovers expenditures for pollution control technologies, replacement generation, undepreciated plant balances and associated operating costs from customers, there can be no assurance in the future that AEP will recover the remaining costs associated with such plants.  Failure to recover these costs could reduce future net income and cash flows and possibly harm financial condition. 

Regulation of CO2 emissions could materially increase costs to AEP and its customers or cause some electric generating units to be uneconomical to operate or maintain. (Applies to all Registrants except AEP Texas, AEPTCo and OPCo)

In 2014, the Federal EPA issued standards for new, modified and reconstructed units, and a guideline for the development of SIPs that would reduce carbon CO2 emissions from existing utility units (the Clean Power Plan). In 2019, the Federal EPA repealed the Clean Power Plan, and replaced it with new guidelines called the Affordable Clean Energy (ACE) rule. In January 2021, the U.S. Court of Appeals for the District of Columbia Circuit vacated the ACE Rule and remanded it to the Federal EPA. The new administration has announced addressing climate change as a policy priority. Costs of compliance with the environmental regulation of CO2 emissions, if any, could reduce future net income and negatively impact financial condition and/or could cause AEP to retire generating capacity prior to the end of its estimated useful life. Although AEP typically recovers environmental expenditures, there can be no assurance in the future that AEP can recover such costs which could reduce future net income and cash flows and possibly harm financial condition.

Courts adjudicating nuisance and other similar claims in the future may order AEP to pay damages or to limit or reduce emissions. (Applies to all Registrants except AEP Texas, AEPTCo and OPCo)

In the past, there have been several cases seeking damages based on allegations of federal and state common law nuisance in which AEP, among others, were defendants.  In general, the actions allege that emissions from the defendants’ power plants constitute a public nuisance.  The plaintiffs in these actions generally seek recovery of damages and other relief.  If future actions are resolved against AEP, substantial modifications or retirement of AEP’s existing coal-fired power plants could be required, and AEP might be required to purchase power from third-parties to fulfill AEP’s commitments to supply power to AEP customers.  This could have a material impact on revenues.  In addition, AEP could be required to invest significantly in additional emission control equipment, accelerate the timing of capital expenditures, pay damages or penalties and/or halt operations.  Unless recovered, those costs could reduce future net income and cash flows and harm financial condition.  Moreover, results of operations and financial position could be reduced due to the timing of recovery of these investments and the expense of ongoing litigation.
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Commodity trading and marketing activities are subject to inherent risks which can be reduced and controlled but not eliminated. (Applies to all Registrants except AEP Texas, AEPTCo and OPCo)

AEP routinely has open trading positions in the market, within guidelines set by AEP, resulting from the management of AEP’s trading portfolio.  To the extent open trading positions exist, fluctuating commodity prices can improve or diminish financial results and financial position.

AEP’s power trading activities also expose AEP to risks of commodity price movements.  To the extent that AEP’s power trading does not hedge the price risk associated with the generation it owns, or controls, AEP would be exposed to the risk of rising and falling spot market prices.

In connection with these trading activities, AEP routinely enters into financial contracts, including futures and options, OTC options, financially-settled swaps and other derivative contracts.  These activities expose AEP to risks from price movements.  If the values of the financial contracts change in a manner AEP does not anticipate, it could harm financial position or reduce the financial contribution of trading operations.

Parties with whom AEP has contracts may fail to perform their obligations, which could harm AEP’s results of operations. (Applies to all Registrants)

AEP sells power from its generation facilities into the spot market and other competitive power markets on a contractual basis. AEP also enters into contracts to purchase and sell electricity, natural gas, emission allowances and coal as part of its power marketing and energy trading operations. AEP is exposed to the risk that counterparties that owe AEP money or the delivery of a commodity, including power, could breach their obligations.  Should the counterparties to these arrangements fail to perform, AEP may be forced to enter into alternative hedging arrangements or honor underlying commitments at then-current market prices that may exceed AEP’s contractual prices, which would cause financial results to be diminished and AEP might incur losses.  Although estimates take into account the expected probability of default by a counterparty, actual exposure to a default by a counterparty may be greater than the estimates predict.

AEP relies on electric transmission facilities that AEP does not own or control.  If these facilities do not provide AEP with adequate transmission capacity, AEP may not be able to deliver wholesale electric power to the purchasers of AEP’s power. (Applies to all Registrants)

AEP depends on transmission facilities owned and operated by other nonaffiliated power companies to deliver the power AEP sells at wholesale.  This dependence exposes AEP to a variety of risks.  If transmission is disrupted, or transmission capacity is inadequate, AEP may not be able to sell and deliver AEP wholesale power.  If a region’s power transmission infrastructure is inadequate, AEP’s recovery of wholesale costs and profits may be limited.  If restrictive transmission price regulation is imposed, the transmission companies may not have sufficient incentive to invest in expansion of transmission infrastructure.

The FERC has issued electric transmission initiatives that require electric transmission services to be offered unbundled from commodity sales.  Although these initiatives are designed to encourage wholesale market transactions, access to transmission systems may not be available if transmission capacity is insufficient because of physical constraints or because it is contractually unavailable.  Management also cannot predict whether transmission facilities will be expanded in specific markets to accommodate competitive access to those markets.


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OVEC may require additional liquidity and other capital support.  (Applies to AEP, APCo, I&M and OPCo)

AEP and several nonaffiliated utility companies, including Energy Harbor (formerly FirstEnergy Solutions), a nonaffiliated party, own OVEC. The Inter-Company Power Agreement (ICPA) defines the rights and obligations and sets the power participation ratio of the parties to it. Under the ICPA, parties are entitled to receive and are obligated to pay for all OVEC capacity (approximately 2,400 MWs) in proportion to their respective power participation ratios. The aggregate power participation ratio of APCo, I&M and OPCo is 43.47%. If a party fails to make payments owed by it under the ICPA, OVEC may not have sufficient funds to honor its payment obligations, including its ongoing operating expenses as well as its indebtedness. As of December 31, 2020, OVEC has outstanding indebtedness of approximately $1.3 billion, of which APCo, I&M, and OPCo are collectively responsible for $555 million through the ICPA. Although they are not an obligor or guarantor, APCo, I&M, and OPCo are responsible for their respective ratio of OVEC’s outstanding debt through the ICPA.

The aggregate power participation ratio of Energy Harbor under the ICPA is 4.85%. A portion of Energy Harbor’s revenues includes amounts authorized under HB 6. The PUCO has rescinded its prior authorization of certain HB 6 related recovery for eligible entities including Energy Harbor. If these amounts are not collected or if HB 6 is repealed and not replaced, Energy Harbor’s financial ability to participate in the ICPA could be adversely impacted. Management is currently unable to predict the outcome of the issues related to HB 6 and will continue to monitor the regulatory and legislative process and any potential impact to OVEC’s cash flows or financial condition. If OVEC does not have sufficient funds to honor its payment obligations, there is risk that APCo, I&M and/or OPCo may need to make payments in addition to their power participation ratio payments. Further, if OVEC’s indebtedness is accelerated for any reason, there is risk that APCo, I&M and/or OPCo may be required to pay some or all of such accelerated indebtedness in amounts equal to their aggregate power participation ratio of 43.47%.

ITEM 1B.   UNRESOLVED STAFF COMMENTS

None.

ITEM 2.   PROPERTIES

GENERATION FACILITIES

As of December 31, 2020, the AEP System owned (or leased where indicated) generation plants, with locations and net maximum power capabilities (winter rating), are shown in the following tables:

Vertically Integrated Utilities Segment
AEGCo     
Plant NameUnitsStateFuel TypeNet Maximum
Capacity (MWs)
Year Plant
or First Unit Commissioned
Rockport, Units 1 and 2 – 50% of each (a)2INSteam - Coal1,310 1984

(a)Rockport Plant, Unit 2 is leased.

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APCo     
Plant NameUnitsStateFuel TypeNet Maximum
Capacity (MWs)
Year Plant
or First Unit Commissioned
Buck3VAHydro11 1912
Byllesby4VAHydro19 1912
Claytor4VAHydro75 1939
Leesville2VAHydro50 1964
London3WVHydro14 1935
Marmet3WVHydro14 1935
Niagara2VAHydro1906
Winfield3WVHydro15 1938
Ceredo6WVNatural Gas516 2001
Dresden3OHNatural Gas613 2012
Smith Mountain5VAPumped Storage585 1965
Amos3WVSteam - Coal2,930 1971
Mountaineer1WVSteam - Coal1,320 1980
Clinch River2VASteam - Natural Gas465 1958
Total MWs   6,629  

I&M     
Plant NameUnitsStateFuel TypeNet Maximum
Capacity (MWs)
Year Plant
or First Unit Commissioned
Berrien Springs12MIHydro1908
Buchanan10MIHydro1919
Constantine4MIHydro1921
Elkhart3INHydro1913
Mottville4MIHydro1923
Twin Branch Hydro8INHydro1904
Deer Creek Solar FarmNAINSolar2016
Olive Solar FarmNAINSolar2016
Twin Branch Solar FarmNAINSolar2016
WatervlietNAMISolar2016
Rockport (Units 1 and 2, 50% of each) (a)2INSteam - Coal1,310 1984
Cook2MISteam - Nuclear2,288 1975
Total MWs   3,634  

NA    Not applicable.
(a)Rockport Plant, Unit 2 is leased.

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The following table provides operating information related to the Cook Plant:
 Cook Plant
 Unit 1Unit 2
Year Placed in Operation19751978
Year of Expiration of NRC License20342037
Nominal Net Electrical Rating in MWs1,0841,204
Annual Capacity Utilization  
202087.2 %94.2 %
201977.3 %84.3 %
201897.9 %79.5 %

KPCo     
Plant NameUnitsStateFuel TypeNet Maximum
Capacity (MWs)
Year Plant
or First Unit Commissioned
Mitchell (a)2WVSteam - Coal780 1971
Big Sandy1KYSteam - Natural Gas280 1963
Total MWs   1,060  

(a)KPCo owns a 50% interest in the Mitchell Plant units.  WPCo owns the remaining 50%. Figures presented reflect only the portion owned by KPCo.

PSO     
Plant NameUnitsStateFuel TypeNet Maximum
Capacity (MWs)
Year Plant
or First Unit Commissioned
Comanche3OKNatural Gas248 1973
Riverside, Units 3 and 42OKNatural Gas160 2008
Southwestern, Units 4 and 52OKNatural Gas170 2008
Weleetka2OKNatural Gas100 1975
Northeastern, Unit 11OKNatural Gas470 1961
Northeastern, Unit 31OKSteam - Coal469 1979
Northeastern, Unit 21OKSteam - Natural Gas434 1961
Riverside, Units 1 and 22OKSteam - Natural Gas901 1974
Southwestern, Units 1, 2 and 33OKSteam - Natural Gas451 1952
Tulsa2OKSteam - Natural Gas325 1956
Total MWs   3,728  

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SWEPCo     
Plant NameUnitsStateFuel TypeNet Maximum
Capacity (MWs)
Year Plant
or First Unit Commissioned
Mattison4ARNatural Gas315 2007
Stall3LANatural Gas534 2010
Flint Creek (a)1ARSteam - Coal258 1978
Turk (a)1ARSteam - Coal477 2012
Welsh (b)2TXSteam - Coal1,053 1977
Dolet Hills (a)(c)1LASteam - Lignite257 1986
Pirkey (a)(d)1TXSteam - Lignite580 1985
Arsenal Hill1LASteam - Natural Gas110 1960
Knox Lee1TXSteam - Natural Gas344 1950
Lieberman3LASteam - Natural Gas217 1947
Wilkes3TXSteam - Natural Gas889 1964
Total MWs   5,034  

(a)Jointly-owned with nonaffiliated entities.  Figures presented reflect only the portion owned by SWEPCo. The Arkansas jurisdictional portion of SWEPCo’s interest in Turk Plant is not in rate base.
(b)In November 2020, management announced it will cease using coal at the Welsh Plant in 2028.
(c)In March 2020, management announced plans to retire the plant in 2021.
(d)In November 2020, management announced plans to retire the plant in 2023.


WPCo     
Plant NameUnitsStateFuel TypeNet Maximum
Capacity (MWs)
Year Plant
or First Unit Commissioned
Mitchell (a)2WVSteam - Coal780 1971

(a)WPCo owns 50% in the Mitchell Plant units. KPCo owns the remaining 50%. Figures presented reflect only the portion owned by WPCo.

Generation & Marketing Segment

AGR
     
Plant NameUnitsStateFuel TypeNet Maximum
Capacity (MWs)
Year Plant
or First Unit Commissioned
Racine2OHHydro48 1982
Cardinal1OHSteam - Coal595 1967
Total MWs   643  


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Renewable Power
Size of Energy ResourceAEP Energy Supply, LLC DivisionRenewable
Energy Resource
LocationIn-Service or
Under Construction
1,307 MWAEP RenewablesWindEight states (a)In-service
128 MWAEP RenewablesWindKansasUnder Construction
20 MWAEP RenewablesSolarCaliforniaIn-service
20 MWAEP RenewablesSolarUtahIn-service
50 MWAEP RenewablesSolarNevadaIn-service
152 MWAEP OnSite PartnersSolarSixteen states (b)In-service
9 MWAEP OnSite PartnersSolarTwo states (c)Under Construction

(a)    Colorado, Hawaii, Indiana, Kansas, Michigan, Minnesota, Pennsylvania, and Texas.
(b)    California, Colorado, Florida, Hawaii, Illinois, Iowa, Minnesota, Nebraska, New Hampshire, New Jersey, New Mexico, New York, Ohio, Rhode Island, Texas and Vermont.
(c)    Ohio and Wisconsin.

TRANSMISSION AND DISTRIBUTION FACILITIES

The following tables set forth the total overhead circuit miles of transmission and distribution lines of the AEP System and its operating companies.

Vertically Integrated Utilities Segment
Total Overhead Circuit Miles of Transmission and Distribution Lines
APCo51,675 
I&M21,201 
KGPCo1,407 
KPCo11,152 
PSO18,196 
SWEPCo26,134 
WPCo1,733 
Total Circuit Miles131,498 

Transmission and Distribution Utilities Segment
Total Overhead Circuit Miles of Transmission and Distribution Lines
OPCo44,838 
AEP Texas46,079 
Total Circuit Miles90,917 
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AEP Transmission Holdco Segment

The following table sets forth the total overhead circuit miles of transmission lines of certain wholly-owned and joint venture-owned entities:
Total Overhead Circuit Miles of Transmission Lines
ETT1,808 
IMTCo696 
OHTCo863 
OKTCo928 
WVTCo250 
Pioneer43 
Prairie Wind Transmission216 
Transource Missouri167 
Transource West Virginia24 
Total Circuit Miles4,995 

TITLE TO PROPERTY

The AEP System’s generating facilities are generally located on lands owned in fee simple.  The greater portion of the transmission and distribution lines of the AEP System has been constructed over lands of private owners pursuant to easements or along public highways and streets pursuant to appropriate statutory authority.  The rights of AEP’s public utility subsidiaries in the realty on which their facilities are located are considered adequate for use in the conduct of their business.  Minor defects and irregularities customarily found in title to properties of like size and character may exist, but such defects and irregularities do not materially impair the use of the properties.  AEP’s public utility subsidiaries generally have the right of eminent domain which permits them, if necessary, to acquire, perfect or secure titles to or easements on privately held lands used or to be used in their utility operations.  Legislation in Ohio and Virginia has restricted the right of eminent domain previously granted for power generation purposes.

SYSTEM TRANSMISSION LINES AND FACILITY SITING

Laws in the states of Arkansas, Indiana, Kentucky, Louisiana, Michigan, Ohio, Tennessee, Texas, Virginia and West Virginia require prior approval of sites of generating facilities and/or routes of high-voltage transmission lines.  AEP has experienced delays and additional costs in constructing facilities as a result of proceedings conducted pursuant to such statutes and in proceedings in which AEP’s operating companies have sought to acquire rights-of-way through condemnation.  These proceedings may result in additional delays and costs in future years.

CONSTRUCTION PROGRAM

With input from its state utility commissions, the AEP System continuously assesses the adequacy of its transmission, distribution, generation and other facilities to plan and provide for the reliable supply of electric power and energy to its customers.  In this assessment process, assumptions are continually being reviewed as new information becomes available and assessments and plans are modified, as appropriate.  AEP forecasts approximately $7.5 billion of construction expenditures for 2021. Estimated construction expenditures are subject to periodic review and modification and may vary based on the ongoing effects of regulatory constraints, environmental regulations, business opportunities, market volatility, economic trends, weather, legal reviews and the ability to access capital.  See the “Budgeted Capital Expenditures” section of Management’s Discussion and Analysis of Financial Condition and Results of Operations included in the 2020 Annual Report for additional information.

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POTENTIAL UNINSURED LOSSES

Some potential losses or liabilities may not be insurable or the amount of insurance carried may not be sufficient to meet potential losses and liabilities, including liabilities relating to damage to AEP’s generation plants and costs of replacement power.  Unless allowed to be recovered through rates, future losses or liabilities which are not completely insured could reduce net income and impact the financial conditions of AEP and other AEP System companies.  For risks related to owning a nuclear generating unit, see the “Nuclear Contingencies” section of Note 6 - Commitments, Guarantees and Contingencies included in the 2020 Annual Report for additional information.

ITEM 3.   LEGAL PROCEEDINGS

For a discussion of material legal proceedings, see Note 6 - Commitments, Guarantees and Contingencies included in the 2020 Annual Report for additional information.

ITEM 4.   MINE SAFETY DISCLOSURE

The Federal Mine Safety and Health Act of 1977 (Mine Act) imposes stringent health and safety standards on various mining operations. The Mine Act and its related regulations affect numerous aspects of mining operations, including training of mine personnel, mining procedures, equipment used in mine emergency procedures, mine plans and other matters. SWEPCo, through its ownership of DHLC, a wholly-owned lignite mining subsidiary of SWEPCo, is subject to the provisions of the Mine Act.

The Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank Act) requires companies that operate mines to include in their periodic reports filed with the SEC, certain mine safety information covered by the Mine Act.  Exhibit 95 “Mine Safety Disclosure Exhibit” contains the notices of violation and proposed assessments received by DHLC under the Mine Act for the quarter ended December 31, 2020.

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PART II

ITEM 5.   MARKET FOR REGISTRANTS’ COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

AEP

In addition to the AEP Common Stock Information section below, the remaining information required by this item is incorporated herein by reference to the material under the “Dividend Policy and Restrictions” section of Management’s Discussion and Analysis of Financial Condition and Results of Operations included in the 2020 Annual Report.

During the quarter ended December 31, 2020, neither AEP nor its publicly-traded subsidiaries purchased equity securities that are registered by AEP or its publicly-traded subsidiaries pursuant to Section 12 of the Exchange Act.

AEP Texas, APCo, I&M, OPCo, PSO and SWEPCo

The common stock of these companies is held solely by AEP.  For more information see the “Dividend Restrictions” section of Note 14 - Financing Activities included in the 2020 Annual Report.

AEPTCo

AEP owns the entire interest in AEPTCo through its wholly-owned subsidiary AEP Transmission Holdco.

AEP COMMON STOCK INFORMATION

AEP common stock is principally traded using the trading symbol “AEP” on the NASDAQ Stock Market.  As of December 31, 2020, AEP had 55,475 registered shareholders. The performance graph below compares the cumulative total return among AEP, the S&P 500 Index and the S&P Electric Utilities Index over a five year period. The performance graph assumes an initial investment of $100 on December 31, 2015 and that all dividends were reinvested.

aep-20201231_g3.jpg

Source: S&P Dow Jones Indices LLC. Data as of December 31, 2020. Past performance is no guarantee of future results. Chart provided for illustrative purposes.

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ITEM 6.   SELECTED FINANCIAL DATA

The selected financial data previously required by Item 301 of Regulation S-K has been omitted in reliance on SEC Release No. 33-10890, Management’s Discussion and Analysis, Selected Financial Data, and Supplementary Financial Information.

ITEM 7.   MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

AEP

The information required by this item is incorporated herein by reference to the material under Management’s Discussion and Analysis of Financial Condition and Results of Operations in the 2020 Annual Report. Year-to-year comparisons between 2019 and 2018 have been omitted from this Form 10-K but may be found in "Management's Discussion and Analysis of Financial Condition" in Part II, Item 7 of our Form 10-K for the fiscal year ended December 31, 2019, which specific discussion is incorporated herein by reference.

AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO and SWEPCo

Omitted pursuant to Instruction I(2)(a).  Management’s narrative analysis of the results of operations and other information required by Instruction I(2)(a) is incorporated herein by reference to the material under Management’s Discussion and Analysis of Financial Condition and Results of Operations in the 2020 Annual Report.

ITEM 7A.   QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO and SWEPCo

The information required by this item is incorporated herein by reference to the material under the “Quantitative and Qualitative Disclosures About Market Risk” section of Management’s Discussion and Analysis of Financial Condition and Results of Operations in the 2020 Annual Report.

ITEM 8.   FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

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2020 Annual Reports

American Electric Power Company, Inc. and Subsidiary Companies
AEP Texas Inc. and Subsidiaries
AEP Transmission Company, LLC and Subsidiaries
Appalachian Power Company and Subsidiaries
Indiana Michigan Power Company and Subsidiaries
Ohio Power Company and Subsidiaries
Public Service Company of Oklahoma
Southwestern Electric Power Company Consolidated







Audited Financial Statements and
Management’s Discussion and Analysis of Financial Condition and Results of Operations







aep-20201231_g4.jpg

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AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
INDEX OF ANNUAL REPORTS
Page
Number
Management’s Report on Internal Control Over Financial Reporting
AEP Texas Inc. and Subsidiaries:
Management’s Narrative Discussion and Analysis of Results of Operations
Report of Independent Registered Public Accounting Firm
Management’s Report on Internal Control Over Financial Reporting
Consolidated Financial Statements
AEP Transmission Company, LLC and Subsidiaries:
Management’s Narrative Discussion and Analysis of Results of Operations
Report of Independent Registered Public Accounting Firm
Management’s Report on Internal Control Over Financial Reporting
Consolidated Financial Statements
Management’s Report on Internal Control Over Financial Reporting
Management’s Report on Internal Control Over Financial Reporting
Management’s Report on Internal Control Over Financial Reporting
Management’s Report on Internal Control Over Financial Reporting
Management’s Report on Internal Control Over Financial Reporting

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AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
EXECUTIVE OVERVIEW

Company Overview

AEP is one of the largest investor-owned electric public utility holding companies in the United States.  AEP’s electric utility operating companies provide generation, transmission and distribution services to more than five million retail customers in Arkansas, Indiana, Kentucky, Louisiana, Michigan, Ohio, Oklahoma, Tennessee, Texas, Virginia and West Virginia.

AEP’s subsidiaries operate an extensive portfolio of assets including:

Approximately 223,000 circuit miles of distribution lines that deliver electricity to 5.5 million customers.
Approximately 40,000 circuit miles of transmission lines, including approximately 2,200 circuit miles of 765 kV lines, the backbone of the electric interconnection grid in the eastern United States.
Approximately 22,000 MWs of regulated owned generating capacity and approximately 4,700 MWs of regulated PPA capacity in 2 RTOs as of December 31, 2020, one of the largest complements of generation in the United States.

COVID-19

In March 2020, COVID-19 was declared a pandemic by the World Health Organization and the Centers for Disease Control and Prevention. Its rapid spread around the world and throughout the United States prompted many countries, including the United States, to institute restrictions on travel, public gatherings and certain business operations. These restrictions significantly disrupted economic activity in AEP’s service territory and reduced demand for energy, particularly from commercial and industrial customers in 2020. Although AEP cannot predict the severity or duration of the impact of the COVID-19 pandemic, AEP currently anticipates a 0.2% increase in weather-normalized retail sales volume in 2021 as compared to 2020. For the year ended December 31, 2020, AEP experienced a reduction in weather-normalized retail sales volume of 2.2% as compared to the same period in 2019 primarily driven by a 5.7% decrease in the industrial customer class and a 4.2% decrease in the commercial customer class offset by an increase in demand of 3.2% from the residential customer class. The reduction in weather-normalized retail sales volume of 2.2% did not result in a significant decrease in the corresponding retail margins for the year ended December 31, 2020 as the increase in higher margin residential sales volumes partially offset the decreases in the industrial and commercial sales volumes. Furthermore, the rate design for certain industrial customers includes demand provisions designed to cover the fixed portion of utility costs minimizing the impact of the fluctuations in usage on revenues. AEP’s load forecast is highly dependent on many factors including, but not limited to, the speed and strength of economic recovery and the extent and duration of the next wave of COVID-19 infection. If the severity of the economic disruption increases, AEP’s future results of operations, financial condition, and cash flows could be further adversely impacted. See Customer Demand for additional information.

During the first quarter of 2020, AEP’s electric operating companies informed both retail customers and state regulators that disconnections for non-payment were temporarily suspended. Shortly thereafter, AEP’s state regulators also imposed temporary moratoria on customary disconnection practices. During the third and the fourth quarters of 2020, most state regulators began to lift restrictions on disconnects. As of December 31, 2020, AEP had resumed disconnections in its regulated jurisdictions with the exception of Virginia, Kentucky and Arkansas. Disconnections resumed in Kentucky during January 2021. AEP continues to work with regulators and stakeholders in Virginia and Arkansas and management currently anticipates resuming customary disconnection practices in the first half of 2021. However, this timing could change if there is new legislation or other regulatory directives issued in the future. Continuing adverse economic conditions may result in the inability of customers to pay for electric service, which could affect revenue recognition and the collectability of accounts receivable.
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Throughout 2020, the Registrants reviewed current collections experience with historical trends, specifically reviewing metrics such as cash collections, days sales outstanding, daily customer deposits and aging summaries. In addition, the Registrants reviewed historical loss information generally comprised of a rolling 12-month average, in conjunction with a qualitative assessment of elements that impact the collectability of receivables, such as changes in economic factors, regulatory matters, industry trends, customer credit factors, payment plan options and other programs available to customers. Based on this review, the Registrants’ accounts receivable aging was negatively impacted primarily due to the suspension of customer disconnects, but has continued to improve throughout the fourth quarter of 2020 as disconnect moratoriums have ended in most jurisdictions. Accounts receivable aging is also improving due to AEP proactively engaging with customers to collect payments or establish payment arrangements for outstanding balances. AEP has received, from the states of Virginia and West Virginia, $10 million and $20 million, respectively, to apply to residential customer balances that are past-due. In addition, customers in other states have access to various programs that assist customers who have accumulated larger than normal past-due balances. As of December 31, 2020, AEP currently does not expect accounts receivable aging to have a material adverse impact on the Registrants’ allowance for uncollectible accounts based on considerations of the COVID-19 impacts and past trends during times of economic instability. Management continues to monitor developments affecting suspensions of disconnections and its impact on customer collections. Further deterioration in AEP’s ability to collect from its customers could significantly impact AEP’s future results of operations, financial conditions and cash flows.

In May 2020, AEP Credit amended its receivables securitization agreement to increase the eligibility criteria related to aged receivable requirements for the participating affiliated utility subsidiaries in response to the COVID-19 pandemic. As of December 31, 2020, the affiliated utility subsidiaries are in compliance with all requirements under the agreement. To the extent that an affiliated utility subsidiary is deemed ineligible under the agreement, the affiliated utility subsidiary would no longer participate in the receivables securitization agreement and the Registrants would need to rely on additional sources of funding for operation and working capital, which may adversely impact liquidity. The receivables that are ineligible under the receivables securitization agreement are financed with short-term debt at AEP Credit.

The Registrants have worked with their state commissions to achieve deferral authority for incremental expenses incurred due to COVID-19. All of AEP’s regulated jurisdictions have issued COVID-19 orders, granting deferral authority for incremental COVID-19 expenses, with the exception of Kentucky and Tennessee. If any costs related to COVID-19 are not recoverable, it could reduce future net income and cash flows and impact financial condition.

The effects of the continued COVID-19 pandemic and related government responses could also include extended disruptions to supply chains, reduced labor availability, reduced dispatch for certain generation assets and a prolonged reduction in economic activity. These effects could have a variety of adverse impacts to the Registrants, including their ability to operate their facilities. As of December 31, 2020, there were no material adverse impacts to the Registrants’ operations and supplier contracts due to COVID-19. AEP will continue to monitor developments affecting facility operations and will take additional actions necessary in order to mitigate adverse impacts to the Registrants’ future results of operations, financial condition and cash flows.

In addition, the economic disruptions caused by COVID-19 could also adversely impact the impairment risks for certain long-lived assets, equity method investments and goodwill. AEP evaluated these impairment considerations and determined that no such impairments existed as of December 31, 2020.

Market volatility and reduction in collections coupled with longer collection periods due to the expansion of customer payment arrangements could reduce cash from operations and cause an adverse impact to liquidity. During 2020, AEP increased its liquidity position to mitigate the market risk and the collections risk due to COVID-19. During the first quarter of 2020, AEP entered into a $1 billion 364–day term loan to reduce reliance on commercial paper and help mitigate potential future liquidity risks. The $1 billion 364-day term loan was repaid in the fourth quarter of 2020. In addition, during 2020, AEP issued approximately $5.6 billion in long-term debt. As of December 31, 2020, AEP’s available liquidity was $2.5 billion. Management believes the Registrants have adequate liquidity under existing credit facilities. In the first quarter of 2020, AEP shifted capital expenditures of
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$500 million out of 2020 into future periods to further mitigate adverse liquidity impacts. In the second quarter of 2020, AEP reinstated $100 million of capital expenditures back into 2020 that had previously been deferred. To the extent that future access to the capital markets or the cost of funding is adversely affected by COVID-19, future results of operations, financial condition, and cash flows may be adversely impacted.

In March 2020, the CARES Act was signed into law. The CARES Act includes tax relief provisions such as: (a) an AMT Credit Refund, (b) a 5-year NOL carryback from years 2018-2020 and (c) delayed payment of employer payroll taxes. Pursuant to the CARES Act, AEP, APCo and OPCo requested and in July received refunds of AMT credit of $20 million, $7 million and $9 million, respectively. In the third quarter of 2020, AEP also requested a $95 million refund of taxes paid in 2014 under the 5-year NOL carryback provision of the CARES Act. AEP carried back a NOL generated on the 2019 Federal income tax return at a 21% federal corporate income tax rate to the 2014 Federal income tax return at a 35% corporate income tax rate. As a result of the change in the corporate income tax rates between the two periods, AEP realized a tax benefit of $48 million primarily at the Generation & Marketing segment. Management will continue to monitor potential legislation and any impacts to the AMT Credit and NOL refunds that were filed in 2020 pursuant to the CARES Act. The Registrants deferred payments of the employer share of payroll taxes for the period March 27, 2020 through December 31, 2020 and will pay 50% of the obligation by December 31, 2021 and the remaining 50% by December 31, 2022. As of December 31, 2020, the Registrants have deferred $55 million of the employer share of payroll taxes.

In December 2020, the CAA of 2021 was signed into law. The CAA of 2021 includes: (a) COVID-19 tax relief and tax extender provisions including extensions of time to begin construction on and placed in-service assets generating PTCs and ITCs, (b) 100% deductibility of business meals in 2021 and 2022 and (c) an extension of the work opportunity tax credit. The ITC percentage has been increased for projects starting construction through 2023 and placed in-service by the end of 2025. The PTC has been extended for an additional year, to include projects started in 2021 and completed in 2025. These provisions provide time and flexibility on the construction start and in-service dates.

The Registrants have taken steps to mitigate the potential risks to customers, suppliers and employees posed by the spread of COVID-19. The Registrants have updated and implemented a company-wide pandemic plan to address specific aspects of COVID-19. This plan guides emergency response, business continuity and the precautionary measures AEP is taking on behalf of its employees and the public. The Registrants have taken extra precautions for employees who work in the field and for employees who work in their facilities, and have work from home policies where appropriate. The Registrants will continue to monitor developments affecting both their workforce and customers, and will take additional precautions that management determines are necessary in order to mitigate the impacts. AEP continues to focus on providing safe, uninterrupted service to its customers, which includes the implementation of strong physical and cyber-security measures to ensure that its systems remain functional with a partially remote workforce. As of December 31, 2020, there has been no material adverse impact to the Registrants’ business operations and customer service due to remote work. Management will continue to review and modify plans as conditions change. Despite efforts to manage these impacts to the Registrants, the ultimate impact of COVID-19 also depends on factors beyond management’s knowledge or control, including the duration and severity of this outbreak as well as third-party actions taken to contain its spread and mitigate its public health effects. Therefore, management cannot estimate the potential future impact to financial position, results of operations and cash flows, but the impacts could be material.

Customer Demand

AEP’s weather-normalized retail sales volumes for the year ended December 31, 2020 decreased by 2.2% from the year ended December 31, 2019. Weather-normalized residential sales increased 3.2% for the year ended December 31, 2020 compared to the year ended December 31, 2019. AEP’s 2020 industrial sales volumes decreased 5.7% compared to 2019. The decline in industrial sales was spread across many industries. Weather-normalized commercial sales decreased by 4.2% in 2020 compared to 2019.

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In 2021, AEP anticipates weather-normalized retail sales volumes will increase by 0.2%. The industrial class is expected to increase by 1.9% in 2021, while weather-normalized residential sales volumes are projected to decrease by 1.1%. Finally, AEP projects weather-normalized commercial sales volumes to decrease by 0.5%.
aep-20201231_g5.jpg
(a)Percentage change for the year ended December 31, 2020 as compared to the year ended December 31, 2019.
(b)Forecasted percentage change for the year ended December 31, 2021 compared to the year ended December 31, 2020.

Regulatory Matters

AEP’s public utility subsidiaries are involved in rate and regulatory proceedings at the FERC and their state commissions.  Depending on the outcomes, these rate and regulatory proceedings can have a material impact on results of operations, cash flows and possibly financial condition. AEP is currently involved in the following key proceedings. See Note 4 - Rate Matters for additional information.

2017-2019 Virginia Triennial Review - In March 2020, APCo submitted its 2017-2019 Virginia triennial earnings review filing and base rate case with the Virginia SCC as required by state law. APCo requested a $65 million annual increase in base rates based upon a proposed 9.9% ROE. Triennial reviews are subject to an earnings test, which provides that 70% of any earnings in excess of 70 basis points above APCo’s Virginia SCC authorized ROE would be refunded to customers. In such case, the Virginia SCC could also lower APCo’s Virginia retail base rates on a prospective basis. Virginia law provides that costs associated with asset impairments of retired coal generation assets, or automated meters, or both, which a utility records as an expense, shall be attributed to the test periods under review in a triennial review proceeding, and be deemed recovered. In 2015, APCo retired the Sporn Plant, the Kanawha River Plant, the Glen Lyn Plant, Clinch River Unit 3 and the coal portions of Clinch River Units 1 and 2 (collectively, the retired coal-fired generation assets). The net book value of the Virginia jurisdictional share of these plants was $93 million before cost of removal, including materials and supplies inventory and ARO balances. Based on management’s interpretation of Virginia law and more certainty regarding APCo’s triennial revenues, expenses and resulting earnings upon reaching the end of the three-year review period, APCo recorded a pretax expense of $93 million related to its previously retired coal-fired generation assets in December 2019. As a result, management deemed these costs to be substantially recovered by APCo during the triennial review period. Inclusive of the Virginia jurisdictional share of the $93 million expense associated with APCo’s retired coal-fired generation assets, APCo calculated its 2017-2019 Virginia earnings for the triennial period to be below the authorized ROE range.


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In November 2020, the Virginia SCC issued an order concluding that APCo earned above its authorized ROE but within its ROE band for the 2017-2019 period, resulting in no refund to customers and no change to APCo base rates on a prospective basis. The Virginia SCC also disagreed with APCo’s treatment of the retired coal-fired generation assets for regulatory purposes, and instead adopted the Virginia SCC Staff’s recommendation to treat the remaining unrecovered costs of the retired coal-fired generation assets as a regulatory asset to be amortized over 10 years as of the June 2015 retirement date. The Virginia SCC’s adoption of the Staff’s recommended regulatory treatment of the coal-fired generation assets resulted in a net $40 million increase to APCo’s 2020 pretax income. In addition, the Virginia SCC’s order also included: (a) implementation of the Staff-modified APCo 2017 depreciation study effective January 1, 2018 and (b) implementation of the Staff-modified APCo 2019 depreciation study effective January 1, 2020. The adoption of these depreciation studies resulted in an approximate $47 million reduction to APCo’s 2020 pretax income comprised of a $44 million reduction to revenues for amounts recognized in advance of the recording of depreciation expense for the periods January 2018 through October 2020 and a $3 million increase in depreciation expense for the periods November and December 2020. A corresponding regulatory liability was recorded for the $44 million reduction to revenues. Also in November 2020, APCo filed a notice of appeal of the Virginia SCC’s order with the Virginia Supreme Court. In December 2020, an intervenor filed a petition at the Virginia SCC requesting reconsideration of: (a) the failure of the Virginia SCC to apply a threshold earnings test to the approved regulatory asset for APCo’s closed coal-fired generation assets, (b) the Virginia SCC’s use of a 2011 benchmark study to measure the replacement value of capacity for purposes of APCo’s 2017 – 2019 earnings test and (c) the reasonableness and prudency of APCo’s investments in AMI meters. Also in December 2020, APCo filed a petition at the Virginia SCC requesting reconsideration of: (a) certain issues related to APCo’s going-forward rates and (b) the Virginia SCC’s decision to deny APCo tariff changes that align rates with underlying costs. For APCo’s going-forward rates, APCo requested that the Virginia SCC clarify its final order and whether APCo’s current rates will allow it to earn a fair return. If the Virginia SCC’s order did conclude on APCo’s ability to earn a fair return through existing base rates, APCo further requested that the Virginia SCC clarify whether it has the authority to also permit an increase in base rates. If the Virginia SCC did not conclude on APCo’s ability to earn a fair return, APCo requested the Virginia SCC provide such a conclusion. In January 2021, as requested by the Virginia SCC, APCo filed briefs related to the petition for reconsideration.

2020 Ohio Base Rate Case - In June 2020, OPCo filed a request with the PUCO for a $42 million annual increase in base rates based upon a proposed 10.15% ROE net of existing riders. In November 2020, PUCO staff filed testimony supporting an annual revenue decrease ranging from $102 million to $123 million based upon an ROE of 8.76% to 9.78%. The staff’s proposal included a disallowance of plant in-service which could result in a write-off of up to $27 million. In addition, the staff recommended that capitalized incentives be excluded from base rates prospectively and also recommended annual revenue caps for the DIR of $57 million in 2021, $78 million in 2022, $96 million in 2023 and $46 million for the first five months of 2024. In December 2020, OPCo and intervenors filed objections. A procedural schedule for the case is pending due to ongoing settlement discussions.

Hurricane Laura - In August 2020, Hurricane Laura hit the coasts of Louisiana and Texas, causing power outages to more than 130,000 customers across SWEPCo’s service territories. Prior to Hurricane Laura, SWEPCo did not have a catastrophe reserve or automatic deferral authority within any of its jurisdictions. In October 2020, the LPSC issued an order allowing Louisiana utilities, including SWEPCo, to establish a regulatory asset to track and defer expenses associated with Hurricane Laura. In October 2020, as part of the 2020 Texas Base Rate Case, SWEPCo requested deferral authority of incremental other operation and maintenance expenses. As of December 31, 2020, management estimates that SWEPCo has incurred incremental other operation and maintenance expenses of $84 million ($82 million of which has been deferred as a regulatory asset related to the Louisiana jurisdiction) and incremental capital expenditures of $23 million, all of which is related to the Louisiana jurisdiction.


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2012 Texas Base Rate Case - In 2012, SWEPCo filed a request with the PUCT to increase annual base rates primarily due to the completion of the Turk Plant. In 2013, the PUCT issued an order affirming the prudence of the Turk Plant. In July 2018, the Texas Third Court of Appeals reversed the PUCT’s judgment affirming the prudence of the Turk Plant and remanded the issue back to the PUCT. In January 2019, SWEPCo and the PUCT filed petitions for review with the Texas Supreme Court. In the fourth quarter of 2019 and first quarter of 2020, SWEPCo and various intervenors filed briefs with the Texas Supreme Court. In August 2020, the Texas Supreme Court granted SWEPCo’s petition for review and oral arguments were held in December 2020. SWEPCo expects a decision from the Texas Supreme Court in 2021. As of December 31, 2020, the net book value of Turk Plant was $1.4 billion, before cost of removal, including materials and supplies inventory and CWIP. SWEPCo’s Texas jurisdictional share of the Turk Plant investment is approximately 33%.

In July 2019, clean energy legislation (HB 6) which offers incentives for power-generating facilities with zero or reduced carbon emissions was signed into law by the Ohio Governor.  HB 6 phased out current energy efficiency programs as of December 31, 2020, including shared savings revenues of $26 million annually and renewable mandates after 2026. HB 6 also provided for the recovery of existing renewable energy contracts on a bypassable basis through 2032 and included a provision for recovery of OVEC costs through 2030 which will be allocated to all electric distribution utilities on a non-bypassable basis.  OPCo’s Inter-Company Power Agreement for OVEC terminates in June 2040. In July 2020, an investigation led by the U.S. Attorney’s Office resulted in a federal grand jury indictment of the Speaker of the Ohio House of Representatives, Larry Householder, four other individuals, and Generation Now, an entity registered as a 501(c)(4) social welfare organization, in connection with a racketeering conspiracy involving the adoption of HB 6. In light of the allegations in the indictment, proposed legislation has been introduced that would repeal HB 6. The outcome of the U.S. Attorney’s Office investigation and its impact on HB 6 is not known. If the provisions of HB 6 were to be eliminated, it is unclear whether and in what form the Ohio General Assembly would pass new legislation addressing similar issues. In August 2020, an AEP shareholder filed a putative class action lawsuit against AEP and certain of its officers for alleged violations of securities laws. In January and February 2021, two AEP shareholders filed two derivative actions purporting to assert claims on behalf of AEP against certain AEP officers and directors based on allegations similar to those in the putative securities class action. See Litigation Related to Ohio House Bill 6 section of Litigation below for additional information. To the extent that OPCo is unable to recover the costs of renewable energy contracts on a bypassable basis by the end of 2032, recover costs of OVEC after 2030, fully recover energy efficiency costs incurred through 2020 or incurs significant costs defending against the securities class action or the derivative actions, it could reduce future net income and cash flows and impact financial condition.

In April 2020, the Virginia Clean Economy Act was signed into law by the Virginia Governor and became effective in July 2020. The law includes the following requirements: (a) Virginia electric utilities to retire no later than 2045 all electric generating units located in Virginia that emit carbon as a by-product, (b) APCo to produce 100% of the company’s power to serve Virginia customers from renewable sources by 2050 with increasing percentages of mandatory renewable energy sources each year and (c) Virginia electric utilities to achieve increasing annual energy efficiency savings from 2022-2025 using 2019 as the base year. This law also provides that if the Virginia SCC finds in any triennial review that revenue reductions related to energy efficiency programs approved and deployed since the utility's previous triennial review have caused the utility to earn more than 70 basis points below its authorized rate of return, the Virginia SCC shall order increases to the utility's rates necessary to recover such revenue reductions. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.

In December 2020, APCo and WPCo filed a proposal with the WVPSC to implement an investment tracker surcharge mechanism for recovering costs associated with capital investment made between base rate cases. The initial filing requests a total annual increase of $50 million ($41 million related to APCo), which represents recovery of costs associated with infrastructure investments made over an approximate three-year period since the companies’ last base rate case filing in 2018. The filing also proposes that APCo and
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WPCo could submit annual filings with requested increases capped to a percentage of total retail revenues (3.5% in the first year and 3% in subsequent filings with an overall cap of 9.5%). If a future base rate case is filed, the surcharge would reset to zero on implementation of the new rates. In January 2021, WVPSC staff filed a motion recommending that the WVPSC reject the proposal. If APCo and WPCo do not receive approval to recover these incremental investments through the proposed tracker surcharge mechanism between base rate cases, it could cause a temporary reduction in future net income and cash flows and impact financial condition until APCo and WPCo can seek approval in their next base rate case.

Utility Rates and Rate Proceedings

The Registrants file rate cases with their regulatory commissions in order to establish fair and appropriate electric service rates to recover their costs and earn a fair return on their investments. The outcomes of these regulatory proceedings impact the Registrants’ current and future results of operations, cash flows and financial position.

The following tables show the Registrants’ completed and pending base rate case proceedings in 2020. See Note 4 - Rate Matters for additional information.

Completed Base Rate Case Proceedings
Approved RevenueApprovedNew Rates
CompanyJurisdictionRequirement Increase (Decrease)ROEEffective
(in millions)
I&MMichigan$36.4 (a)9.86%February 2020
I&MIndiana60.0 (b)9.7%March 2020
AEP TexasTexas(40.0)9.4%June 2020
APCoVirginia— (c)9.2%February 2021
KPCoKentucky52.7 9.3%January 2021

(a)See “2019 Michigan Base Rate Case” section of Note 4 Rate Matters in the 2019 Annual Report for additional information.
(b)Phased-in through an increase in base rates which included: (a) an annual increase in base rates of $44 million effective March 2020 and (b) an annual increase in base rates of $60 million effective January 2021 based on the IURC-approved forecast of December 31, 2020 Indiana jurisdictional electric plant in-service. The order rejected I&M’s proposed re-allocation of capacity costs related to the loss of a significant FERC wholesale contract, which negatively impacted I&M’s annual pretax earnings by approximately $20 million starting June 2020.
(c)APCo filed a notice of appeal with the Virginia Supreme Court and a petition requesting reconsideration with the Virginia SCC. In addition, an intervenor has also filed a petition requesting reconsideration with the Virginia SCC.

Pending Base Rate Case Proceedings
Commission Staff/
FilingRequested RevenueRequestedIntervenor Range of
CompanyJurisdictionDateRequirement IncreaseROERecommended ROE
(in millions)
OPCoOhioJune 2020$42.3 10.15%8.76% - 9.78%
SWEPCoTexasOctober 2020105.0 (a)10.35%(b)
SWEPCoLouisianaDecember 2020134.0 10.35%(c)

(a)The request would move transmission and distribution interim revenues recovered through riders into base rates. Eliminating these riders would result in a net annual requested base rate increase of $90 million primarily due to increased investments.
(b)Intervenor and staff testimony is scheduled to be filed in March and April 2021, respectively.
(c)Awaiting procedural schedule.
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Dolet Hills Power Station and Related Fuel Operations

During the second quarter of 2019, the Dolet Hills Power Station initiated a seasonal operating schedule. In January 2020, in accordance with the terms of SWEPCo’s settlement of its base rate review filed with the APSC, management announced that SWEPCo will seek regulatory approval to retire the Dolet Hills Power Station by the end of 2026. DHLC provides 100% of the fuel supply to Dolet Hills Power Station. After careful consideration of current economic conditions, and particularly for the benefit of their customers, management of SWEPCo and CLECO determined DHLC would not proceed developing additional Oxbow Lignite Company (Oxbow) mining areas for future lignite extraction and ceased extraction of lignite at the mine in May 2020. Based on these actions, management revised the estimated useful life of DHLC’s and Oxbow’s assets to coincide with the date at which extraction was discontinued in the second quarter of 2020 and the date at which delivery of lignite is expected to cease in September 2021. Management also revised the useful life of the Dolet Hills Power Station to 2021 based on the remaining estimated fuel supply available for continued seasonal operation. In March 2020, primarily due to the revision in the useful life of DHLC, SWEPCo recorded a revision to increase estimated ARO liabilities by $21 million. In April 2020, SWEPCo and CLECO jointly filed a notification letter to the LPSC providing notice of the cessation of lignite mining.

The Dolet Hills Power Station costs are recoverable by SWEPCo through base rates. SWEPCo’s share of the net investment in the Dolet Hills Power Station is $151 million, including CWIP and materials and supplies, before cost of removal.

Fuel costs incurred by the Dolet Hills Power Station are recoverable by SWEPCo through active fuel clauses. Under the fuel agreements, SWEPCo’s fuel inventory and unbilled fuel costs from mining related activities were $131 million as of December 31, 2020. Also, as of December 31, 2020, SWEPCo had a net over-recovered fuel balance of $35 million, which includes fuel burned at the Dolet Hills Power Station. Additional operational and land-related costs are expected to be incurred by DHLC and Oxbow and billed to SWEPCo prior to the closure of the Dolet Hills Power Station and recovered through fuel clauses.

In October 2020, SWEPCo filed a request with the LPSC for recovery of the Louisiana share of these additional fuel costs. SWEPCo’s filing proposes to defer $36 million of fuel costs in 2021 and recover the deferral plus carrying costs over five years beginning in 2022.

If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.

Pirkey Power Plant and Related Fuel Operations

In November 2020, management announced plans to retire the Pirkey Power Plant in 2023. The Pirkey Power Plant costs are recoverable by SWEPCo through base rates. SWEPCo’s share of the net investment in the Pirkey Power Plant is $212 million, including CWIP, before cost of removal. Sabine is a mining operator providing mining services to the Pirkey Power Plant. Under the provisions of the mining agreement, SWEPCo is required to pay, as part of the cost of lignite delivered, an amount equal to mining costs plus a management fee. SWEPCo expects fuel deliveries, including billings of all fixed and operating costs, from Sabine to cease during the first quarter of 2023. Under the fuel agreements, SWEPCo’s fuel inventory and unbilled fuel costs from mining related activities were $193 million as of December 31, 2020. Also, as of December 31, 2020, SWEPCo had a net over-recovered fuel balance of $35 million, which includes fuel burned at the Pirkey Power Plant. Additional operational costs are expected to be incurred by Sabine and billed to SWEPCo, as well as land-related costs incurred by SWEPCo, prior to the closure of the Pirkey Power Plant and recovered through fuel clauses.

If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.


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Renewable Generation

The growth of AEP’s renewable generation portfolio reflects the company’s strategy to diversify generation resources to provide clean energy options to customers that meet both their energy and capacity needs.

Contracted Renewable Generation Facilities

AEP continues to develop its renewable portfolio within the Generation & Marketing segment.  Activities include working directly with wholesale and large retail customers to provide tailored solutions based upon market knowledge, technology innovations and deal structuring which may include distributed solar, wind, combined heat and power, energy storage, waste heat recovery, energy efficiency, peaking generation and other forms of cost reducing energy technologies.  The Generation & Marketing segment also develops and/or acquires large scale renewable generation projects that are backed with long-term contracts with creditworthy counterparties.

In November 2020, AEP acquired an additional 10% interest, or approximately 30 MWs, in Santa Rita East. The project is located in west Texas and was placed in-service in July 2019. Long-term virtual power purchase agreements are in place with nonaffiliates for the project’s generation. See Note 17 - Variable Interest Entities and Equity Method Investments for additional information.

In November 2020, AEP signed a Purchase and Sale Agreement with a nonaffiliate to acquire a 75% interest in the 100 MW Dry Lake Solar Project located in southern Nevada. Management expects the transaction to close in the first quarter of 2021 and the solar project is expected to be in-service in the second quarter of 2021.

As of December 31, 2020, subsidiaries within AEP’s Generation & Marketing segment had approximately 1,549 MWs of contracted renewable generation projects in-service.  In addition, as of December 31, 2020, these subsidiaries had approximately 137 MWs of renewable generation projects under construction with total estimated capital costs of $208 million related to these projects.

Regulated Renewable Generation Facilities

In 2020, PSO received approval from the OCC and SWEPCo received approval from the APSC and LPSC to acquire the North Central Wind Energy Facilities, comprised of three Oklahoma wind facilities totaling 1,485 MWs, on a fixed cost turn-key basis at completion. Both the APSC and LPSC approved the flex-up option, agreeing to acquire the Texas portion, which the PUCT denied. PSO will own 45.5% and SWEPCo will own 54.5% of the project, which will cost approximately $2 billion.

In May 2020, the IRS issued a notice extending the “Continuity Safe Harbor” deadlines for qualifying renewable energy projects that began construction in 2016 and 2017 by one year as many projects are facing supply chain and other project development delays caused by COVID-19. Under the May 2020 IRS notice, qualifying renewable energy projects that began construction in 2016 and 2017 and which are placed in-service by the end of 2021 and 2022, respectively, will satisfy the Continuity Safe Harbor. Provided that each facility does satisfy the Continuity Safe Harbor, under the current IRS guidance, the 199 MW wind facility will qualify for 100% of the federal PTC, and the remaining two wind facilities, totaling 1,286 MWs, will qualify for 80% of the federal PTC.

Having regulatory approval, and the expectation that all three wind facilities will be eligible for the IRS extension of the “Continuity Safe Harbor,” PSO and SWEPCo are proceeding with the full 1,485 MW development of these three projects. The 199 MW wind facility is targeted to be acquired and placed in-service in March 2021. The 287 MW wind facility is targeted to be acquired and placed in-service in December 2021 and the 999 MW wind facility is targeted to be acquired and placed in-service between December 2021 and April 2022.


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Hydroelectric Generation

Evaluating Sale of Hydroelectric Generation

In March 2020, management placed 10 hydroelectric generation plants under study for a potential sale. In April 2020, the Virginia Clean Economy Act was signed into law by the Virginia Governor. The new law will provide renewable credits to APCo for its existing hydroelectric generation plants. As a result of the new law, management removed the three APCo hydroelectric generation plants (London, Marmet and Winfield) from the list of plants identified for potential sale. In December 2020, management decided they would only proceed with the potential sale of Racine. The two Racine units have a net maximum capacity of 48 MWs and the net book value is $45 million as of December 31, 2020. In February 2021, AEP signed an agreement to sell Racine to a nonaffiliated party. The sale of Racine requires FERC approval. The sale is expected to close in the second quarter of 2021 and result in an immaterial gain. Racine was not presented as Held for Sale on AEP’s Consolidated Balance Sheets due to immateriality.

Federal Tax Reform

Based on current regulatory orders received, management anticipates amortization of $233 million of Excess ADIT in 2021 ($64 million of Excess ADIT subject to normalization requirements and $169 million of Excess ADIT that is not subject to normalization requirements). Customer usage or new regulatory orders could result in changes to these estimates. Management anticipates amortizing the following ranges of Excess ADIT that is not subject to normalization requirements during the years 2022 through 2026:

Annual Amortization of Excess ADIT
Not Subject to Normalization Requirements
YearRange
(in millions)
2022$75.0 -$105.0 
202368.0 -98.0 
202435.0 -65.0 
20255.0 -26.0 
20265.0 -25.0 

Merchant Portion of Turk Plant

SWEPCo constructed the Turk Plant, a base load 600 MW (650 MW net maximum capacity) pulverized coal ultra-supercritical generating unit in Arkansas, which was placed in-service in December 2012 and is included in the Vertically Integrated Utilities segment. SWEPCo owns 73% (440 MWs/477 MWs) of the Turk Plant and operates the facility.

The APSC granted approval for SWEPCo to build the Turk Plant by issuing a Certificate of Environmental Compatibility and Public Need (CECPN) for the SWEPCo Arkansas jurisdictional share of the Turk Plant (approximately 20%). Following an appeal by certain intervenors, the Arkansas Supreme Court issued a decision that reversed the APSC’s grant of the CECPN. In June 2010, in response to an Arkansas Supreme Court decision, the APSC issued an order which reversed and set aside the previously granted CECPN. This share of the Turk Plant output is currently not subject to cost-based rate recovery and is being sold into the wholesale market. Approximately 80% of the Turk Plant investment is recovered under cost-based rate recovery in Texas, Louisiana and through SWEPCo’s wholesale customers under FERC-based rates. As of December 31, 2020, the net book value of Turk Plant was $1.4 billion, before cost of removal, including materials and supplies inventory and CWIP. If SWEPCo cannot ultimately recover its investment and expenses related to the Turk Plant, it could reduce future net income and cash flows and impact financial condition.


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FERC Transmission ROE Methodology

Management continues to monitor FERC’s 2019 Notice of Inquiry regarding base ROE policy, FERC’s 2020 Notice of Proposed Rulemaking regarding transmission incentives policy, and various other matters pending before FERC with the potential to affect FERC transmission ROE methodology.

In the second quarter of 2019, FERC approved settlement agreements establishing base ROEs of 9.85% (10.35% inclusive of RTO incentive adder of 0.5%) and 10% (10.5% inclusive of RTO incentive adder of 0.5%) for AEP’s PJM and SPP transmission-owning subsidiaries, respectively. In the second quarter of 2020, FERC Order 569A determined the base ROE for MISO’s transmission owning members, including AEP’s MISO transmission-owning subsidiaries, should be 10.02% (10.52% inclusive of the RTO incentive adder of 0.5%).

If FERC makes any changes to its ROE and incentive policies, they would be applied, as applicable, to AEP’s PJM, SPP and MISO transmission owning subsidiaries on a prospective basis, and could affect future net income and cash flows and impact financial condition.

Impacts of Severe Winter Weather in February 2021

In February 2021, many of AEP’s service territories and customers were impacted by severe winter weather and extreme cold temperatures resulting in power outages, extensive damage to transmission and distribution infrastructure and disruption to the energy markets.

Storm Costs

Based on the information currently available, APCo, KPCo and SWEPCo currently estimate significant February 2021 storm restoration expenditures as shown in the table below. Management currently anticipates the storm restoration expenditures will be more heavily weighted towards other operation and maintenance expenses as compared to capital expenditures. Management will continue to refine these storm cost estimates as restoration efforts are completed and final costs become available.

Total Estimated February 2021
Storm Restoration Expenditures
(in millions)
APCo$65.0-$75.0
KPCo$75.0-$95.0
SWEPCo$30.0-$40.0

Management plans to seek regulatory recovery of these costs. If any of the storm costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.
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February 2021 Severe Winter Weather Impacts in SPP

The February 2021 severe winter weather also had a significant impact in SPP resulting in the declaration of Energy Emergency Alert Levels 2 and 3 for the first time in SPP’s history. The winter storm increased the demand for natural gas and restricted the available natural gas supply resulting in significantly increased market prices for natural gas power plants to meet reliability needs for the SPP electric system. From February 9, 2021, to February 20, 2021, based on the information currently available, PSO’s and SWEPCo’s preliminary estimates of natural gas expenses and purchases of electricity are as follows:

PSOSWEPCo
(in millions)
Estimated Natural Gas Expenses$175.0 $375.0 
Estimated Electricity Purchases650.0 — 
$825.0 $375.0 

The amounts in the table above represent preliminary estimates as of February 25, 2021, and are subject to final settlement as additional information becomes available. In addition, SPP notified PSO and SWEPCo of additional collateral requirements of approximately $868 million on a cumulative basis for the companies due March 2, 2021. Subsequently, SPP filed a waiver request with the FERC that would grant a limited waiver for Load Serving Entities to post this additional collateral requirement between February 24, 2021 and March 11, 2021. FERC approved the waiver request on February 24, 2021.

PSO and SWEPCo have active fuel clauses that allow for the recovery of prudently incurred fuel and purchased power expenses. Given the significance of these costs, PSO and SWEPCo expect regulators to perform a heightened review of the costs. Management believes these costs are probable of future recovery. However, the recovery of these costs from customers may be extended over longer than usual time periods to mitigate the impact on customer bills. Nevertheless, PSO and SWEPCo’s payments to suppliers are due in March 2021.

PSO and SWEPCo are evaluating financing alternatives including funding contributions from Parent and long-term debt issuances to address the timing difference between the payment to suppliers and recovery from customers. If either PSO or SWEPCo is unable to recover these fuel and purchased power expenses or recover these expenses in a timely manner, it could reduce future net income and cash flows and impact financial condition.

ERCOT

In response to the extreme winter weather event, the Governor of Texas issued a Declaration of a State of Disaster for all counties in Texas. While recovery from the emergency conditions is continuing, some market conditions and activities have yet to return to normal. To assist with a return to normalcy, the PUCT issued an order that placed a temporary moratorium on customer disconnections due to non-payment for transmission and distribution utilities. This moratorium will be in effect until otherwise ordered by the PUCT.
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LITIGATION

In the ordinary course of business, AEP is involved in employment, commercial, environmental and regulatory litigation. Since it is difficult to predict the outcome of these proceedings, management cannot predict the eventual resolution, timing or amount of any loss, fine or penalty. Management assesses the probability of loss for each contingency and accrues a liability for cases that have a probable likelihood of loss if the loss can be estimated.  Adverse results in these proceedings have the potential to reduce future net income and cash flows and impact financial condition. See Note 4 – Rate Matters and Note 6 – Commitments, Guarantees and Contingencies for additional information.

Rockport Plant Litigation

In 2013, the Wilmington Trust Company filed a complaint in the U.S. District Court for the Southern District of New York against AEGCo and I&M alleging that it would be unlawfully burdened by the terms of the modified NSR consent decree after the Rockport Plant, Unit 2 lease expiration in December 2022.  The terms of the consent decree allow the installation of environmental emission control equipment, repowering, refueling or retirement of the unit.  The plaintiffs seek a judgment declaring that the defendants breached the lease, must satisfy obligations related to installation of emission control equipment and indemnify the plaintiffs.  The New York court granted a motion to transfer this case to the U.S. District Court for the Southern District of Ohio.

AEGCo and I&M sought and were granted dismissal by the U.S. District Court for the Southern District of Ohio of certain of the plaintiffs’ claims, including claims for compensatory damages, breach of contract, breach of the implied covenant of good faith and fair dealing and indemnification of costs. Plaintiffs voluntarily dismissed the surviving claims that AEGCo and I&M failed to exercise prudent utility practices with prejudice, and the court issued a final judgment. The plaintiffs subsequently filed an appeal in the U.S. Court of Appeals for the Sixth Circuit.

In 2017, the U.S. Court of Appeals for the Sixth Circuit issued an opinion and judgment affirming the district court’s dismissal of the owners’ breach of good faith and fair dealing claim as duplicative of the breach of contract claims, reversing the district court’s dismissal of the breach of contract claims and remanding the case for further proceedings.

Thereafter, AEP filed a motion with the U.S. District Court for the Southern District of Ohio in the original NSR litigation, seeking to modify the consent decree. The district court granted the owners’ unopposed motion to stay the lease litigation to afford time for resolution of AEP’s motion to modify the consent decree. The consent decree was modified based on an agreement among the parties in July 2019. The district court’s stay of the lease litigation expired in August 2020. Upon expiration of the stay, plaintiffs filed a motion for partial summary judgment, arguing that the consent decree violates the facility lease and the participation agreement and requesting that the district court enter a judgment for the plaintiffs on their breach of contract claim. AEP’s memorandum in opposition to plaintiffs’ motion for partial summary judgement was filed in October 2020. At the parties’ request, the district court stayed the case until February 16, 2021 to provide the parties an opportunity to resolve the case, and the court has since extended the stay until April 26, 2021. See “Modification of the New Source Review Litigation Consent Decree” section below for additional information.

Management will continue to defend against the claims and believes its financial statements appropriately reflect the potential outcome of the pending litigation. The ultimate outcome of the pending litigation could reduce future net income and cash flows and impact financial condition.


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Patent Infringement Complaint

In July 2019, Midwest Energy Emissions Corporation and MES Inc. (collectively, the plaintiffs) filed a patent infringement complaint against various parties, including AEP Texas, AGR, Cardinal Operating Company and SWEPCo (collectively, the AEP Defendants). The complaint alleges that the AEP Defendants infringed two patents owned by the plaintiffs by using specific processes for mercury control at certain coal-fired generating stations. The complaint was resolved in December 2020 and did not have a material impact on net income, cash flows or financial condition.

Claims Challenging Transition of American Electric Power System Retirement Plan to Cash Balance Formula

The American Electric Power System Retirement Plan (the Plan) has received a letter written on behalf of four participants (the Claimants) making a claim for additional plan benefits and purporting to advance such claims on behalf of a class. When the Plan’s benefit formula was changed in the year 2000, AEP provided a special provision for employees hired before January 1, 2001, allowing them to continue benefit accruals under the then benefit formula for a full 10 years alongside of the new cash balance benefit formula then being implemented.  Employees who were hired on or after January 1, 2001 accrued benefits only under the new cash balance benefit formula.  The Claimants have asserted claims that: (a) the Plan violates the requirements under the Employee Retirement Income Security Act (ERISA) intended to preclude back-loading the accrual of benefits to the end of a participant’s career, (b) the Plan violates the age discrimination prohibitions of ERISA and the Age Discrimination in Employment Act and (c) the company failed to provide required notice regarding the changes to the Plan.  AEP has responded to the Claimants providing a reasoned explanation for why each of their claims have been denied. The denial of those claims was appealed to the AEP System Retirement Plan Appeal Committee and the Committee upheld the denial of claims. Management will continue to defend against the claims.  Management is unable to determine a range of potential losses that is reasonably possible of occurring.

Litigation Related to Ohio House Bill 6

In August 2020, an AEP shareholder filed a putative class action lawsuit in the United States District Court for the Southern District of Ohio against AEP and certain of its officers for alleged violations of securities laws. The complaint alleges misrepresentations or omissions by AEP regarding: (a) its alleged participation in public corruption with respect to the passage of Ohio House Bill 6, (b) its regulatory, legislative and lobbying activities in Ohio and (c) its clean energy strategy. The complaint seeks monetary damages among other forms of relief. The company will continue to defend against the claims. Management is unable to determine a range of potential losses that is reasonably possible of occurring.

In January 2021, an AEP shareholder filed a derivative action in the United States District Court for the Southern District of Ohio purporting to assert claims on behalf of AEP against certain AEP officers and directors. In February 2021, a second AEP shareholder filed a similar derivative action in the Court of Common Pleas of Franklin County, Ohio. The derivative complaints allege the officers and directors made misrepresentations and omissions similar to those alleged in the putative securities class action lawsuit filed against AEP. The complaints assert claims for: (a) breach of fiduciary duty, (b) waste of corporate assets and (c) unjust enrichment and seek monetary damages and changes to AEP’s corporate governance and internal policies among other forms of relief. The company will continue to defend against the claims. Management is unable to determine a range of potential losses that is reasonably possible of occurring.

ENVIRONMENTAL ISSUES

AEP has a substantial capital investment program and incurs additional operational costs to comply with environmental control requirements.  Additional investments and operational changes will be made in response to existing and anticipated requirements to reduce emissions from fossil generation and in response to rules governing the beneficial use and disposal of coal combustion by-products, clean water and renewal permits for certain water discharges.

AEP is engaged in litigation about environmental issues, was notified of potential responsibility for the clean-up of contaminated sites and incurred costs for disposal of SNF and future decommissioning of the nuclear units.  AEP,
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along with other parties, challenged some of the Federal EPA requirements.  Management is engaged in the development of possible future requirements including the items discussed below.  Management believes that further analysis and better coordination of these environmental requirements would facilitate planning and lower overall compliance costs while achieving the same environmental goals.

AEP will seek recovery of expenditures for pollution control technologies and associated costs from customers through rates in regulated jurisdictions.  Environmental rules could result in accelerated depreciation, impairment of assets or regulatory disallowances.  If AEP cannot recover the costs of environmental compliance, it would reduce future net income and cash flows and impact financial condition.

Environmental Controls Impact on the Generating Fleet

The rules and proposed environmental controls discussed below will have a material impact on AEP System generating units.  Management continues to evaluate the impact of these rules, project scope and technology available to achieve compliance.  As of December 31, 2020, the AEP System owned generating capacity of approximately 24,400 MWs, of which approximately 12,100 MWs were coal-fired.  Management continues to refine the cost estimates of complying with these rules and other impacts of the environmental proposals on fossil generation. Based upon management estimates, AEP’s future investment to meet these existing and proposed requirements ranges from approximately $350 million to $700 million through 2027.

The cost estimates will change depending on the timing of implementation and whether the Federal EPA provides flexibility in finalizing proposed rules or revising certain existing requirements.  The cost estimates will also change based on: (a) potential state rules that impose more stringent standards, (b) additional rulemaking activities in response to court decisions, (c) actual performance of the pollution control technologies installed, (d) changes in costs for new pollution controls, (e) new generating technology developments, (f) total MWs of capacity retired and replaced, including the type and amount of such replacement capacity and (g) other factors.  In addition, management continues to evaluate the economic feasibility of environmental investments on regulated and competitive plants.

Modification of the New Source Review Litigation Consent Decree

In 2007, the U.S. District Court for the Southern District of Ohio approved a consent decree between AEP subsidiaries in the eastern area of the AEP System and the Department of Justice, the Federal EPA, eight northeastern states and other interested parties to settle claims that the AEP subsidiaries violated the NSR provisions of the CAA when they undertook various equipment repair and replacement projects over a period of nearly 20 years.  The consent decree’s terms include installation of environmental control equipment on certain generating units, a declining cap on SO2 and NOX emissions from the AEP System and various mitigation projects.

In 2017, AEP filed a motion with the district court seeking to modify the consent decree to eliminate an obligation to install future controls at Rockport Plant, Unit 2 if AEP does not acquire ownership of that unit, and to modify the consent decree in other respects to preserve the environmental benefits of the consent decree.  The other parties to the consent decree opposed AEP’s motion. The district court granted AEP’s request to delay the deadline to install Selective Catalytic Reduction (SCR) technology at Rockport Plant, Unit 2 until June 2020. Construction of the SCR technology was completed by June 1, 2020, testing was conducted, and the unit was released for dispatch on June 5, 2020.

In May 2019, the parties filed a proposed order to modify the consent decree. The proposed order requires AEP to enhance the dry sorbent injection (DSI) system on both units at the Rockport Plant by the end of 2020, and meet 30-day rolling average emission rates for SO2 and NOX at the combined stack for the Rockport Plant beginning in 2021. Total SO2 emissions from the Rockport Plant are limited to 10,000 tons per year beginning in 2021 and reduce to 5,000 tons per year when Rockport Plant, Unit 1 retires in 2028. The proposed modification was approved by the district court and became effective in July 2019. As part of the modification to the consent decree, I&M agreed to provide an additional $7.5 million to citizens’ groups and the states for environmental mitigation projects. As joint-owners in the Rockport Plant, the $7.5 million payment was shared between AEGCo and I&M based on the joint-ownership agreement.
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Clean Air Act Requirements

The CAA establishes a comprehensive program to protect and improve the nation’s air quality and control sources of air emissions. The states implement and administer many of these programs and could impose additional or more stringent requirements. The primary regulatory programs that continue to drive investments in AEP’s existing generating units include: (a) periodic revisions to NAAQS and the development of SIPs to achieve any more stringent standards, (b) implementation of the regional haze program by the states and the Federal EPA, (c) regulation of hazardous air pollutant emissions under MATS, (d) implementation and review of CSAPR and (e) the Federal EPA’s regulation of greenhouse gas emissions from fossil generation under Section 111 of the CAA. Notable developments in significant CAA regulatory requirements affecting AEP’s operations are discussed in the following sections.

National Ambient Air Quality Standards

The Federal EPA reviewed the existing standards for NO2 and SO2 in 2018 and 2019, respectively, and decided to retain the standards without change. Implementation of these standards is underway. The Federal EPA recently reviewed the existing standards for PM and ozone and in December 2020 announced both standards would be retained without change.

The Federal EPA finalized non-attainment designations for the 2015 ozone standard in 2018. The Federal EPA confirmed that for states included in the CSAPR program, there are no additional interstate transport obligations, as all areas of the country are expected to attain the 2008 ozone standard before 2023. Challenges to the 2015 ozone standard and the Federal EPA’s determination that CSAPR satisfies certain states’ interstate transport obligations were filed in the U.S. Court of Appeals for the District of Columbia Circuit. In August 2019, the court upheld the 2015 primary ozone standard, but remanded the secondary welfare-based standard for further review. The court vacated the Federal EPA’s determination that CSAPR fulfilled the states’ interstate transport obligations, because the Federal EPA’s modeling analysis did not demonstrate that all significant contributions would be eliminated by the attainment deadlines for downwind states. Any further changes will require additional rulemaking. Management cannot currently predict the nature, stringency or timing of additional requirements for AEP’s facilities based on the outcome of these activities.

Regional Haze

The Federal EPA issued a Clean Air Visibility Rule (CAVR), detailing how the CAA’s requirement that certain facilities install best available retrofit technology (BART) would address regional haze in federal parks and other protected areas.  BART requirements apply to certain power plants.  CAVR will be implemented through SIPs or FIPs.  In 2017, the Federal EPA revised the rules governing submission of SIPs to implement the visibility programs, including a provision that postpones the due date for the next comprehensive SIP revisions until 2021. Petitions for review of the final rule revisions have been filed in the U.S. Court of Appeals for the District of Columbia Circuit.

The Federal EPA initially disapproved portions of the Arkansas regional haze SIP, but has approved a revised SIP and all of SWEPCo's affected units are in compliance with the relevant requirements.

The Federal EPA also disapproved portions of the Texas regional haze SIP. In 2017, the Federal EPA finalized a FIP that allows participation in the CSAPR ozone season program to satisfy the NOX regional haze obligations for electric generating units in Texas. Additionally, the Federal EPA finalized an intrastate SO2 emissions trading program based on CSAPR allowance allocations. A challenge to the FIP was filed in the U.S. Court of Appeals for the Fifth Circuit and the case is pending the Federal EPA’s reconsideration of the final rule. In August 2018, the Federal EPA proposed to affirm its 2017 FIP approval. In November 2019, in response to comment, the Federal EPA proposed revisions to the intrastate trading program. The Federal EPA finalized the intrastate trading program in July 2020, and that rule has been challenged in the U.S. Court of Appeals for the Fifth Circuit as well as in the U.S. Court of Appeals for the District of Columbia Circuit. Management cannot predict the outcome of that litigation, although management supports the intrastate trading program as a compliance alternative to source-specific controls and has intervened in the litigation in support of the Federal EPA.
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Cross-State Air Pollution Rule

In 2011, the Federal EPA issued CSAPR as a replacement for the Clean Air Interstate Rule, a regional trading program designed to address interstate transport of emissions that contributed significantly to downwind non-attainment with the 1997 ozone and PM NAAQS.  CSAPR relies on SO2 and NOX allowances and individual state budgets to compel further emission reductions from electric utility generating units.  Interstate trading of allowances is allowed on a restricted sub-regional basis.

Petitions to review the CSAPR were filed in the U.S. Court of Appeals for the District of Columbia Circuit. In 2015, the court found that the Federal EPA over-controlled the SO2 and/or NOX budgets of 14 states. The court remanded the rule to the Federal EPA for revision consistent with the court’s opinion while CSAPR remained in place.

In 2016, the Federal EPA issued a final rule, the CSAPR Update, to address the remand and to incorporate additional changes necessary to address the 2008 ozone standard. The CSAPR Update significantly reduced ozone season budgets in many states and discounted the value of banked CSAPR ozone season allowances beginning with the 2017 ozone season. In 2019, the appeals court remanded the CSAPR Update to the Federal EPA because it determined the Federal EPA had not properly considered the attainment dates for downwind areas in establishing its partial remedy, and should have considered whether there were available measures to control emissions from sources other than generating units. Any further changes to the CSAPR rule will require additional rulemaking.

In October 2020, the Federal EPA proposed a revised CSAPR Update rule, which would substantially reduce the ozone season NOX budgets in 2021-2024. The Federal EPA recently released the underlying modeling and budget allocations and management is evaluating the potential impacts of this proposed rule.

Mercury and Other Hazardous Air Pollutants (HAPs) Regulation

In 2012, the Federal EPA issued a rule addressing a broad range of HAPs from coal and oil-fired power plants.  The rule established unit-specific emission rates for units burning coal on a 30-day rolling average basis for mercury, PM (as a surrogate for particles of non-mercury metals) and hydrogen chloride (as a surrogate for acid gases).  In addition, the rule proposed work practice standards for controlling emissions of organic HAPs and dioxin/furans, with compliance required within three years. Management obtained administrative extensions for up to one year at several units to facilitate the installation of controls or to avoid a serious reliability problem.

In 2014, the U.S. Court of Appeals for the District of Columbia Circuit denied all of the petitions for review of the 2012 final rule. Various intervenors filed petitions for further review in the U.S. Supreme Court.

In 2015, the U.S. Supreme Court reversed the decision of the U.S. Court of Appeals for the District of Columbia Circuit. The court remanded the MATS rule to the Federal EPA to consider costs in determining whether to regulate emissions of HAPs from power plants. In 2016, the Federal EPA issued a supplemental finding concluding that, after considering the costs of compliance, it was appropriate and necessary to regulate HAP emissions from coal and oil-fired units. Petitions for review of the Federal EPA’s determination were filed in the U.S. Court of Appeals for the District of Columbia Circuit. In 2018, the Federal EPA released a revised finding that the costs of reducing HAP emissions to the level in the current rule exceed the benefits of those HAP emission reductions. The Federal EPA also determined that there are no significant changes in control technologies and the remaining risks associated with HAP emissions do not justify any more stringent standards. Therefore, the Federal EPA proposed to retain the current MATS standards without change. In April 2020, the Federal EPA released a final rule adopting the conclusions set forth in the proposal and retaining the existing MATS standards. The rule has been challenged in the U.S. Court of Appeals for the District of Columbia Circuit.

Climate Change, CO2 Regulation and Energy Policy

In 2015, the Federal EPA published the final CO2 emissions standards for new, modified and reconstructed fossil generating units, and final guidelines for the development of state plans to regulate CO2 emissions from existing sources, known as the Clean Power Plan (CPP). Implementation of the CPP was stayed by the U.S. Supreme Court pending the outcome of legal challenges, and the CPP was ultimately repealed by the Federal EPA in 2019 and
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replaced with the Affordable Clean Energy (ACE) rule. ACE established a framework for states to adopt standards of performance for utility boilers based on heat rate improvements for such boilers. States were to submit their plans for implementing the ACE rule in 2022, and the Federal EPA would have had up to two years to review and approve a plan or disapprove it and adopt a federal plan. However, in January 2021, the U.S. Court of Appeals for the D.C. Circuit vacated the ACE rule and remanded it to the Federal EPA. It is too soon to predict how the Federal EPA will respond to the court’s remand.

In 2018, the Federal EPA filed a proposed rule revising the standards for new sources and determined that partial carbon capture and storage is not the best system of emission reduction because it is not available throughout the U.S. and is not cost-effective. That rule has not been finalized. Management continues to actively monitor these rulemaking activities.

While no federal regulatory requirements to reduce CO2 emissions are in place, AEP has taken action to reduce and offset CO2 emissions from its generating fleet. AEP expects CO2 emissions from its operations to continue to decline due to the retirement of some of its coal-fired generation units, and actions taken to diversify the generation fleet and increase energy efficiency where there is regulatory support for such activities. The majority of the states where AEP has generating facilities passed legislation establishing renewable energy, alternative energy and/or energy efficiency requirements that can assist in reducing carbon emissions.  In April 2020, Virginia enacted clean energy legislation to allow the state to participate in the Regional Greenhouse Gas Initiative, require the retirement of all fossil-fueled generation by 2045 and require 100% renewable energy to be provided to Virginia customers by 2050. Management is taking steps to comply with these requirements, including increasing wind and solar installations, purchasing renewable power and broadening AEP System’s portfolio of energy efficiency programs.

In February 2021, AEP announced new intermediate and long-term CO2 emission reduction goals, based on the output of the company’s integrated resource plans, which take into account economics, customer demand, grid reliability and resiliency, regulations and the company’s current business strategy. The intermediate goal is an 80% reduction from 2000 CO2 emission levels from AEP generating facilities by 2030; the long-term goal is net-zero CO2 emissions from AEP generating facilities by 2050. AEP’s total estimated CO2 emissions in 2020 were approximately 44 million metric tons, a 73% reduction from AEP’s 2000 CO2 emissions. AEP has made significant progress in reducing CO2 emissions from its power generation fleet and expects its emissions to continue to decline. Technological advances, including energy storage, will determine how quickly AEP can achieve zero emissions while continuing to provide reliable, affordable power for customers.

Excessive costs to comply with future legislation or regulations has led to the announcement of early plant closures and could force AEP to close additional coal-fired generation facilities earlier than their estimate useful life. If AEP is unable to recover the costs of its investments, it would reduce future net income and cash flows and impact financial condition.

Coal Combustion Residual (CCR) Rule

In 2015, the Federal EPA published a final rule to regulate the disposal and beneficial re-use of CCR, including fly ash and bottom ash created from coal-fired generating units and FGD gypsum generated at some coal-fired plants.  The rule applies to active CCR landfills and surface impoundments at operating electric utility or independent generation facilities. The rule imposes construction and operating obligations, including location restrictions, liner criteria, structural integrity requirements for impoundments, operating criteria and additional groundwater monitoring requirements to be implemented on a schedule spanning an approximate four-year implementation period. In 2018, some of AEP’s facilities were required to begin monitoring programs to determine if unacceptable groundwater impacts will trigger future corrective measures. Based on additional groundwater data, further studies to design and assess appropriate corrective measures have been undertaken at two facilities.

In a challenge to the final 2015 rule, the parties initially agreed to settle some of the issues.  In 2018, the U.S. Court of Appeals for the District of Columbia Circuit addressed or dismissed the remaining issues in its decision vacating and remanding certain provisions of the 2015 rule.  The provisions addressed by the court’s decision, including changes to the provisions for unlined impoundments and legacy sites, are the subject of further rulemaking that has not been finalized.
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Prior to the court’s decision, the Federal EPA issued the July 2018 rule that modifies certain compliance deadlines and other requirements in the 2015 rule.  In December 2018, challengers filed a motion for partial stay or vacatur of the July 2018 rule. On the same day, the Federal EPA filed a motion for partial remand of the July 2018 rule. The court granted the Federal EPA’s motion. In November 2019, the Federal EPA proposed revisions to implement the court’s decision regarding the timing for closure of unlined surface impoundments along with impoundments not meeting the required distance from an aquifer. The final rule was published in August 2020. In December 2019, the Federal EPA proposed a federal permit program, implementing the Water Infrastructure Improvements for the Nation Act that would apply in states that do not have an approved CCR program.

Other utilities and industrial sources have been engaged in litigation with environmental advocacy groups who claim that releases of contaminants from wells, CCR units, pipelines and other facilities to groundwaters that have a hydrologic connection to a surface water body represent an “unpermitted discharge” under the CWA. Two cases were accepted by the U.S. Supreme Court for further review of the scope of CWA jurisdiction. In April 2020, the Supreme Court issued an opinion remanding one of these cases to the Ninth Circuit based on its determination that discharges from an injection well that make their way to the Pacific Ocean through ground water may require a permit if the distance traveled through ground water, length of time to reach the surface water and other factors make it “functionally equivalent” to a direct discharge from a point source. The second case was also remanded to the lower court. Prior to the Supreme Court’s decision, the Federal EPA opened a rulemaking docket to solicit information to determine whether it should provide additional clarification of the scope of CWA permitting requirements for discharges to groundwater, and issued an interpretive statement finding that discharges to groundwater are not subject to NPDES permitting requirements under the CWA. In December 2020, the Federal EPA issued draft guidance for public comment on applying the outcome of the Supreme Court’s decision and consideration of functionally equivalent factors. Management is unable to predict the impact of these developments on AEP’s facilities.

In August 2020, the Federal EPA revised the CCR rule to include a requirement that unlined CCR storage ponds cease operations and initiate closure by April 11, 2021. The revised rule provides two options that allow facilities to extend the date by which they must cease receipt of coal ash and close the ponds.

The first option provides an extension to cease receipt of CCR no later than October 15, 2023 for most units, and October 15, 2024 for a narrow subset of units; however, the Federal EPA’s grant of such an extension will be based upon a satisfactory demonstration of the need for additional time to develop alternative ash disposal capacity and will be limited to the soonest timeframe technically feasible to cease receipt of CCR. Additionally, each request must undergo formal review, including public comments, and be approved by the Federal EPA. AEP filed applications for additional time to develop alternative disposal capacity at the following plants:

CompanyPlant Name and UnitGenerating
Capacity
Net Book Value (a)Projected
Retirement Date
(in MWs)(in millions)
APCoAmos2,930$2,171.8 2040
APCoMountaineer1,320980.2 2040
SWEPCoFlint Creek Plant258279.2 2038
KPCoMitchell Plant780605.1 2040
WPCoMitchell Plant780603.7 2040
AEGCoRockport Plant, Unit 1655248.9 2028
I&MRockport Plant, Unit 1655573.8 (b)2028

(a)Net book value before cost of removal including CWIP and inventory.
(b)Amount includes a $191 million regulatory asset related to the retired Tanners Creek Plant. The IURC and MPSC authorized recovery of the Tanners Creek Plant regulatory asset over the useful life of Rockport Plant, Unit 1 in 2015 and 2014, respectively.
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In December 2020, APCo filed requests with the Virginia SCC and WVPSC to obtain the regulatory approvals necessary to implement the compliance plans and seek recovery of the estimated $240 million investment for the Amos and Mountaineer plants. In December 2020 and February 2021, WPCo and KPCo filed requests with the WVPSC and KPSC, respectively, to obtain the regulatory approvals necessary to implement the compliance plans and seek recovery of the estimated $132 million investment for the Mitchell Plant. Within those requests, WPCo and KPCo also filed a $25 million alternative with the WVPSC and KPSC, respectively, which would allow the Mitchell Plant to continue operating only through 2028.

The second option is a retirement option, which provides a generating facility an extended operating time without developing alternative CCR disposal. Under the retirement option, a generating facility would have until October 17, 2023 to cease operation and to close CCR storage ponds 40 acres or less in size, or through October 17, 2028 for facilities with CCR storage ponds greater than 40 acres in size. Pursuant to this option, AEP informed the Federal EPA of its intent to retire the Pirkey Power Plant and cease using coal at the Welsh Plant:
CompanyPlant Name and UnitGenerating
Capacity
Net Investment (a)Accelerated Depreciation Regulatory AssetProjected
Retirement Date
(in MWs)(in millions)
SWEPCoPirkey Power Plant580$199.5 $12.2 2023 (b)
SWEPCoWelsh Plants, Units 1 & 31,053549.8 3.6 2028 (c)(d)

(a)Net book value including CWIP excluding cost of removal and materials and supplies.
(b)Pirkey Power Plant is currently being recovered through 2025 in the Louisiana jurisdiction and through 2045 in the Arkansas and Texas jurisdictions.
(c)In November 2020, management announced it will cease using coal at the Welsh Plant in 2028.
(d)Unit 1 is currently being recovered through 2027 in the Louisiana jurisdiction and through 2037 in the Arkansas and Texas jurisdictions. Unit 3 is currently being recovered through 2032 in the Louisiana jurisdiction and through 2042 in the Arkansas and Texas jurisdictions.

AEP may incur significant costs to upgrade or close and replace surface impoundments and landfills used to manage CCR and to conduct any required remedial actions. Under the retirement option above, AEP may need to recover remaining depreciation and estimated closure costs associated with retiring plants over a shorter period. If AEP cannot ultimately recover the costs of environmental compliance and/or the remaining depreciation and estimated closure costs associated with retiring plants in a timely manner, it would reduce future net income and cash flows and impact financial condition.

Closure and post-closure costs have been included in ARO in accordance with the requirements in the final rule. Additional ARO revisions will occur on a site-by-site basis if groundwater monitoring activities conclude that corrective actions are required to mitigate groundwater impacts, which could include costs to remove ash from some unlined units.

In March 2020, Virginia’s Governor signed House Bill 443 (HB 443), effective July 2020, requiring APCo to close certain ash disposal units at the retired Glen Lyn Station by removal of all coal combustion material.  As a result, in June 2020, APCo recorded a $199 million revision to increase estimated Glen Lyn Station ash disposal ARO liabilities.  The closure is required to be completed within 15 years from the start of the excavation process.  HB 443 provides for the recovery of all costs associated with closure by removal through the Virginia environmental rate adjustment clause (E-RAC).  APCo is permitted to record carrying costs on the unrecovered balance of closure costs at a weighted-average cost of capital approved by the Virginia SCC. HB 443 also allows any closure costs allocated to non-Virginia jurisdictional customers, but not collected from such non-Virginia jurisdictional customers, to be recovered from Virginia jurisdictional customers through the E-RAC. APCo will submit filings with the Virginia SCC and the WVPSC requesting recovery of the respective Virginia and West Virginia jurisdictional shares of these Glen Lyn Station ARO costs. As of December 31, 2020, APCo has not yet incurred any incremental costs associated with the removal of coal combustion material at the Glen Lyn Station.

If removal of ash is required without providing similar assurances of cost recovery in regulated jurisdictions, it would impose significant additional operating costs on AEP, which could lead to increased financing costs and liquidity needs. Other units in Virginia, Ohio, West Virginia and Kentucky have already been closed in place in
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accordance with state law programs. Management will continue to participate in rulemaking activities and make adjustments based on new federal and state requirements affecting its ash disposal units.

Clean Water Act Regulations

In 2014, the Federal EPA issued a final rule setting forth standards for existing power plants that is intended to reduce mortality of aquatic organisms impinged or entrained in the cooling water.  The rule was upheld on review by the U.S. Court of Appeals for the Second Circuit. Compliance timeframes are established by the permit agency through each facility’s NPDES permit as those permits are renewed and have been incorporated into permits at several AEP facilities. AEP facilities that have had their wastewater discharge permits renewed have been asked to monitor intake flows or to enhance monitoring practices to assure the current technology is being properly managed to ensure compliance with this rule.

In 2015, the Federal EPA issued a final rule revising effluent limitation guidelines for generating facilities. The rule established limits on FGD wastewater, fly ash and bottom ash transport water and flue gas mercury control wastewater to be imposed as soon as possible after November 2018 and no later than December 2023. These requirements would be implemented through each facility’s wastewater discharge permit. The rule was challenged in the U.S. Court of Appeals for the Fifth Circuit. In 2017, the Federal EPA announced its intent to reconsider and potentially revise the standards for FGD wastewater and bottom ash transport water. The Federal EPA postponed the compliance deadlines for those wastewater categories to be no earlier than 2020, to allow for reconsideration. In April 2019, the Fifth Circuit vacated the standards for landfill leachate and legacy wastewater, and remanded them to the Federal EPA for reconsideration.  In November 2019, the Federal EPA proposed revisions to the guidelines for existing generation facilities. A final rule was signed by the Federal EPA in August 2020 and was published in October 2020. The final rule establishes additional options for reusing and discharging small volumes of bottom ash transport water, provides an exception for retiring units, and extends the compliance deadline to a date as soon as possible beginning one year after the rule was published but no later than December 2025. Management has assessed technology additions and retrofits to comply with the rule and the impacts of the Federal EPA’s recent actions on facilities’ wastewater discharge permitting for FGD wastewater and bottom ash transport water. Permit modifications for affected facilities were filed in January 2021 that reflect the outcome of that assessment.

In 2015, the Federal EPA and the U.S. Army Corps of Engineers jointly issued a final rule to clarify the scope of the regulatory definition of “waters of the United States” in light of recent U.S. Supreme Court cases. Various parties challenged the 2015 rule in different U.S. District Courts, which resulted in a patchwork of applicability of the 2015 rule and its predecessor. In December 2018, the Federal EPA and the U.S. Army Corps of Engineers proposed a replacement rule. In September 2019, the Federal EPA repealed the 2015 rule. The final replacement rule was published in the Federal Register in April 2020 and became effective in June 2020. The final rule limits the scope of CWA jurisdiction to four categories of waters, and clarifies exclusions for ground water, ephemeral streams, artificial ponds and waste treatment systems. Challenges to the final rule and requests for a preliminary injunction have been brought by states and other groups in multiple U.S. District Courts. At this time, none of the jurisdictions in which AEP operates are impacted by a stay. Management is monitoring these various proceedings but is unable to predict the actions of the various courts.

In April 2020, the U.S. District Court for the District of Montana issued a decision vacating the U.S. Army Corps of Engineers’ (Corps) General Nationwide Permit (NWP) 12, which provides standard conditions governing linear utility projects in streams, wetlands and other waters of the United States having minimal adverse environmental impacts. The Court found that in reissuing NWP 12 in 2017, the Corps failed to comply with Section 7 of the Endangered Species Act (ESA), which requires the Corps to consult with the U.S. Fish and Wildlife Service regarding potential impacts on endangered species. The Court remanded the permit back to the Corps to complete its ESA consultation, and also enjoined the Corps from authorizing any dredge or fill activities under NWP 12 pending completion of the consultation process. The Department of Justice filed a motion to stay the injunction and tailor the remedy imposed by the Court. In May 2020, the Court revised its order lifting the injunction for non-oil and gas pipeline construction activities and routine maintenance, inspection and repair activities on existing NWP 12 projects. The Department of Justice appealed the Court’s decision to the Court of Appeals for the Ninth Circuit
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and moved for stay pending appeal, which was denied. In June 2020, the Department of Justice submitted an application to the U.S. Supreme Court requesting a stay of the District Court’s Order, and the Court granted the request with respect to all oil and gas pipelines except the Keystone Pipeline. Management is monitoring the litigation, but is currently unable to predict the impact of future proceedings on current and planned projects.

In September 2020, the Corps issued for public comment the proposed renewal of all General Nationwide Permits. As part of that proposal the Corps narrowed the focus of NWP 12 to only oil and natural gas pipeline activities. The Corps proposed two new Nationwide Permits governing electric utility line and telecommunications activities, and other utility lines (e.g., conveyance of potable water, sewage, other substances), respectively. In January 2021, the Corps issued 16 final Nationwide Permits, including NWP 12 and the two new utility line permits, NWP 57 and NWP 58. The Corps chose not to reissue or modify the remaining Nationwide Permits at this time. The 2017 versions of those permits remain in effect. Management is currently assessing impacts of the rulemaking on current and planned projects.

Impact of Environmental Regulation on Coal-Fired Generation

Compliance with extensive environmental regulations requires significant capital investment in environmental monitoring, installation of pollution control equipment, emission fees, disposal costs and permits. Management continuously evaluates cost estimates of complying with these regulations which may result in a decision to retire coal-fired generating facilities earlier than their currently estimated useful lives.

In addition to the November 2020 announcement related to the Federal EPA’s CCR rules, management also decided not to renew the Rockport Plant, Unit 2 lease when it expires in 2022. Previously, management retired or announced early closure plans for Welsh Unit 2, Oklaunion Power Station, Dolet Hills Power Station and Northeastern Plant Unit 3.

The table below summarizes the net book value, as of December 31, 2020, of generating facilities retired or planned for early retirement:
CompanyPlantNet
Investment (a)
Accelerated Depreciation Regulatory AssetActual/Projected
Retirement
Date
Current Authorized
Recovery
Period
Annual Depreciation (b)
(in millions)(in millions)
SWEPCoDolet Hills Power Station$74.4 $71.2 2021(c)$60.8 
PSONortheastern Plant, Unit 3198.4 110.4 2026(d)14.9 
PSOOklaunion Power Station— 34.4 2020(e)— 
SWEPCoPirkey Power Plant199.5 12.2 2023(f)13.8 
SWEPCoWelsh Plant, Units 1 and 3549.8 3.6 2028 (g)(h)33.3 
SWEPCoWelsh Plant, Unit 2— 35.2 2016(i)— 

(a)Net book value including CWIP excluding cost of removal and materials and supplies.
(b)These amounts represent the amount of annual depreciation that has been collected from customers over the prior 12-month period.
(c)Dolet Hills Power Station is current being recovered through 2026 in the Louisiana jurisdiction and through 2046 in the Arkansas and Texas jurisdictions.
(d)Northeastern Plant, Unit 3 is currently being recovered through 2040.
(e)Oklaunion Power Station is currently being recovered through 2046.
(f)Pirkey Power Plant is currently being recovered through 2025 in the Louisiana jurisdiction and through 2045 in the Arkansas and Texas jurisdictions.
(g)In November 2020, management announced it will cease using coal at the Welsh Plant in 2028.
(h)Welsh Plant, Unit 1 is being recovered through 2027 in the Louisiana jurisdiction and through 2037 in the Arkansas and Texas jurisdictions. Welsh Plant, Unit 3 is being recovered through 2032 in the Louisiana jurisdiction and through 2042 in the Arkansas and Texas jurisdictions.
(i)Welsh Plant, Unit 2 is being recovered over the blended useful life of Welsh Plant, Units 1 and 3.

Management is seeking or will seek regulatory recovery, as necessary, for any net book value remaining when the plants are retired. To the extent the net book value of these generation assets are not deemed recoverable, it could materially reduce future net income, cash flows and impact financial condition.
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RESULTS OF OPERATIONS

SEGMENTS

AEP’s primary business is the generation, transmission and distribution of electricity.  Within its Vertically Integrated Utilities segment, AEP centrally dispatches generation assets and manages its overall utility operations on an integrated basis because of the substantial impact of cost-based rates and regulatory oversight.  Intersegment sales and transfers are generally based on underlying contractual arrangements and agreements.

AEP’s reportable segments and their related business activities are outlined below:

Vertically Integrated Utilities

Generation, transmission and distribution of electricity for sale to retail and wholesale customers through assets owned and operated by AEGCo, APCo, I&M, KGPCo, KPCo, PSO, SWEPCo and WPCo.

Transmission and Distribution Utilities

Transmission and distribution of electricity for sale to retail and wholesale customers through assets owned and operated by AEP Texas and OPCo.
OPCo purchases energy and capacity at auction to serve standard service offer customers and provides transmission and distribution services for all connected load.

AEP Transmission Holdco

Development, construction and operation of transmission facilities through investments in AEPTCo. These investments have FERC-approved returns on equity.
Development, construction and operation of transmission facilities through investments in AEP’s transmission-only joint ventures. These investments have PUCT-approved or FERC-approved returns on equity.

Generation & Marketing

Contracted renewable energy investments and management services.
Marketing, risk management and retail activities in ERCOT, MISO, PJM and SPP.
Competitive generation in PJM.

The remainder of AEP’s activities are presented as Corporate and Other. While not considered a reportable segment, Corporate and Other primarily includes the purchasing of receivables from certain AEP utility subsidiaries, Parent’s guarantee revenue received from affiliates, investment income, interest income and interest expense and other nonallocated costs.

The following discussion of AEP’s 2020 results of operations by operating segment includes an analysis of Gross Margin, which is a non-GAAP financial measure. Gross Margin includes Total Revenues less the costs of Fuel and Other Consumables Used for Electric Generation as well as Purchased Electricity for Resale and Amortization of Generation Deferrals as presented in the Registrants’ statements of income as applicable. Under the various state utility rate-making processes, these expenses are generally reimbursable directly from and billed to customers. As a result, they do not typically impact Operating Income or Earnings Attributable to AEP Common Shareholders. Management believes that Gross Margin provides a useful measure for investors and other financial statement users to analyze AEP’s financial performance in that it excludes the effect on Total Revenues caused by volatility in these expenses. Operating Income, which is presented in accordance with GAAP in AEP’s statements of income, is the most directly comparable GAAP financial measure to the presentation of Gross Margin. AEP’s definition of Gross Margin may not be directly comparable to similarly titled financial measures used by other companies.

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A detailed discussion of AEP’s 2019 results of operations by operating segment can be found in Management’s Discussion and Analysis of Financial Condition and Results of Operation section included in the 2019 Annual Report on Form 10-K filed with the SEC on February 20, 2020.

The following table presents Earnings (Loss) Attributable to AEP Common Shareholders by segment:
Years Ended December 31,
202020192018
(in millions)
Vertically Integrated Utilities$1,061.6 $982.0 $990.5 
Transmission and Distribution Utilities496.4 451.0 527.4 
AEP Transmission Holdco504.8 516.3 369.9 
Generation & Marketing226.9 112.8 135.3 
Corporate and Other(89.6)(141.0)(99.3)
Earnings Attributable to AEP Common Shareholders$2,200.1 $1,921.1 $1,923.8 
aep-20201231_g6.jpg

Note: 2020 Earnings Attributable to AEP Common Shareholders by Segment excludes Corporate and Other which is not considered a reportable segment.

AEP CONSOLIDATED

2020 Compared to 2019

Earnings Attributable to AEP Common Shareholders increased from $1.9 billion in 2019 to $2.2 billion in 2020 primarily due to:

Favorable rate proceedings in AEP’s various jurisdictions.
A planned decrease in Other Operation and Maintenance expenses.
Continued transmission investment, which resulted in higher revenues and income.

These increases were partially offset by:

A decrease in weather-related usage.
A one-time reversal of a regulatory provision in 2019.

AEP’s results of operations by reportable segment are discussed below.
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VERTICALLY INTEGRATED UTILITIES

aep-20201231_g7.jpgaep-20201231_g8.jpg

(a)Other AEP Segments excludes Corporate and Other which is not considered a reportable segment.

Years Ended December 31,
Vertically Integrated Utilities202020192018
(in millions)
Revenues$8,879.4 $9,367.1 $9,645.5 
Fuel and Purchased Electricity2,544.9 3,103.1 3,488.9 
Gross Margin6,334.5 6,264.0 6,156.6 
Other Operation and Maintenance2,754.3 2,934.4 2,959.8 
Asset Impairments and Other Related Charges— 92.9 3.4 
Depreciation and Amortization1,600.5 1,447.0 1,316.2 
Taxes Other Than Income Taxes472.6 460.9 433.2 
Operating Income1,507.1 1,328.8 1,444.0 
Other Income2.4 6.1 17.0 
Allowance for Equity Funds Used During Construction42.2 50.7 35.4 
Non-Service Cost Components of Net Periodic Benefit Cost67.9 67.6 69.9 
Interest Expense(565.0)(568.3)(567.8)
Income Before Income Tax Expense (Benefit) and
Equity Earnings
1,054.6 884.9 998.5 
Income Tax Expense (Benefit)(7.0)(97.7)5.7 
Equity Earnings of Unconsolidated Subsidiary2.9 3.0 2.7 
Net Income1,064.5 985.6 995.5 
Net Income Attributable to Noncontrolling Interests2.9 3.6 5.0 
Earnings Attributable to AEP Common Shareholders$1,061.6 $982.0 $990.5 
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Summary of KWh Energy Sales for Vertically Integrated Utilities
Years Ended December 31,
202020192018
(in millions of KWhs)
Retail:
Residential31,526 32,359 33,908 
Commercial22,225 23,839 24,452 
Industrial32,860 35,252 35,730 
Miscellaneous2,185 2,302 2,330 
Total Retail88,796 93,752 96,420 
Wholesale (a)16,987 20,090 22,682 
Total KWhs105,783 113,842 119,102 

(a)Includes Off-system Sales, municipalities and cooperatives, unit power and other wholesale customers.


aep-20201231_g9.jpg

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Heating degree days and cooling degree days are metrics commonly used in the utility industry as a measure of the impact of weather on revenues.  In general, degree day changes in the eastern region have a larger effect on revenues than changes in the western region due to the relative size of the two regions and the number of customers within each region.
Summary of Heating and Cooling Degree Days for Vertically Integrated Utilities
Years Ended December 31,
202020192018
(in degree days)
Eastern Region
Actual – Heating (a)2,295 2,617 2,886 
Normal – Heating (b)2,727 2,732 2,738 
Actual – Cooling (c)1,222 1,369 1,443 
Normal – Cooling (b)1,104 1,092 1,083 
Western Region
Actual – Heating (a)1,160 1,512 1,599 
Normal – Heating (b)1,464 1,473 1,475 
Actual – Cooling (c)2,117 2,328 2,502 
Normal – Cooling (b)2,253 2,240 2,230 

(a)Heating degree days are calculated on a 55 degree temperature base.
(b)Normal Heating/Cooling represents the thirty-year average of degree days.
(c)Cooling degree days are calculated on a 65 degree temperature base.

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2020 Compared to 2019

Reconciliation of Year Ended December 31, 2019 to Year Ended December 31, 2020
Earnings Attributable to AEP Common Shareholders from Vertically Integrated Utilities
(in millions)
Year Ended December 31, 2019$982.0 
Changes in Gross Margin:
Retail Margins30.7 
Margins from Off-system Sales(12.5)
Transmission Revenues60.3 
Other Revenues(8.0)
Total Change in Gross Margin70.5 
Changes in Expenses and Other:
Other Operation and Maintenance180.1 
Asset Impairments and Other Related Charges92.9 
Depreciation and Amortization(153.5)
Taxes Other Than Income Taxes(11.7)
Other Income(3.7)
Allowance for Equity Funds Used During Construction(8.5)
Non-Service Cost Components of Net Periodic Pension Cost0.3 
Interest Expense3.3 
Total Change in Expenses and Other99.2 
Income Tax Expense(90.7)
Equity Earnings of Unconsolidated Subsidiary(0.1)
Net Income Attributable to Noncontrolling Interests0.7 
Year Ended December 31, 2020$1,061.6 

The major components of the increase in Gross Margin, defined as revenues less the related direct cost of fuel, including consumption of chemicals and emissions allowances, and purchased electricity were as follows:

Retail Margins increased $31 million primarily due to the following:
A $35 million increase in deferred fuel at APCo and WPCo primarily due to the timing of recoverable PJM expenses.
A $20 million increase at APCo and WPCo due to the WVPSC approval of the Mitchell Plant surcharge effective January 1, 2020. Pursuant to the WVPSC approval of the surcharge, this increase was partially offset by the amortization of Excess ADIT not subject to normalization requirements in Income Tax Expense below.
A $17 million increase due to a decrease in customer refunds related to Tax Reform. This increase was partially offset in Income Tax Expense below.
A $14 million increase due to the impact of the 2019 WVPSC order which required APCo and WPCo to offset Excess ADIT not subject to normalization requirements against the deferred fuel under-recovery balance in 2019.
A $10 million increase at APCo and WPCo due to revenue from rate riders primarily in West Virginia. This increase was partially offset in other expense items below.
A $9 million increase due to an environmental expense deferral at APCo.
An $8 million increase in weather-normalized retail margins driven by a $111 million increase in the residential customer class partially offset by a $97 million decrease in the commercial and industrial classes.

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The effect of rate proceedings in AEP’s service territories which included:
A $109 million increase at I&M primarily due to the Indiana and Michigan base rate cases and increases in rider revenues. This increase was partially offset in other expense items below.
A $45 million increase at SWEPCo primarily due to rider increases in all jurisdictions and a base rate revenue increase in Arkansas. This increase was partially offset in other expense items below.
A $10 million increase at PSO due to new base rates implemented in April 2019.
An $8 million increase at APCo and WPCo due to new base rates implemented in 2019 in West Virginia. This increase was partially offset in Depreciation and Amortization expenses below.
These increases were partially offset by:
A $128 million decrease in weather-related usage primarily in the eastern region and primarily in the residential class.
A $66 million decrease in weather-normalized margins for wholesale contracts, including the loss of a significant wholesale contract at I&M.
A $44 million decrease due to the cumulative impact of the implementation of APCo’s 2017 and 2019 generation and distribution depreciation studies as ordered in the Virginia triennial base rate case.
A $13 million decrease in revenue from rate riders at PSO. This decrease was partially offset in other expense items below.
Margins from Off-system Sales decreased $13 million due to weaker market prices for energy in the RTOs which caused a decrease in sales margins and volume. In addition, the historical merchant portion of WPCo’s Mitchell Plant moved to retail rates beginning in January 2020.
Transmission Revenues increased $60 million primarily due to the following:
A $31 million increase as a result of the annual transmission formula rate true-up primarily at SWEPCo. This increase was partially offset by an increase in transmission expenses in SPP.
A $22 million increase due to continued investment in transmission projects primarily at SWEPCo.
A $12 million increase at APCo resulting from the 2017-2019 Virginia triennial base rate case. This increase was offset in Depreciation Expense below.
Other Revenues decreased $8 million primarily due to the following:
A $10 million decrease at I&M primarily due to a decrease in barging revenues by River Transportation Division. This decrease was partially offset in Other Operation and Maintenance expenses below.
An $8 million decrease primarily due to suspension of late fees and disconnections in 2020 as a result of the COVID-19 pandemic.
These decreases were partially offset by:
A $9 million increase at PSO primarily due to business development revenue. This increase was partially offset in other expense items below.

Expenses and Other and Income Tax Expense changed between years as follows:

Other Operation and Maintenance expenses decreased $180 million primarily due to the following:
A $49 million decrease due to the re-establishment of a regulatory asset in 2020 as result of APCo’s 2017-2019 Virginia triennial review which authorized the recovery of previously retired coal-fired generation assets.
A $47 million decrease in plant outage and maintenance expenses primarily at APCo, I&M, WPCo, KPCo and PSO.
A $34 million decrease in charitable contributions primarily driven by the contribution to the AEP Foundation in 2019.
A $32 million decrease in distribution expenses primarily related to vegetation management and other distribution expenses.
A $28 million decrease in transmission expenses primarily related to accelerated vegetation management and maintenance in 2019.
A $15 million decrease due to the capitalization of previously expensed North Central Wind Energy Facilities costs at SWEPCo and PSO.
A $14 million decrease related to a 2020 insurance settlement primarily at SWEPCo and PSO.
An $8 million decrease due to the modification of the NSR consent decree impacting I&M and AEGCo in 2019.
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A $7 million decrease at I&M due to an increased Nuclear Electric Insurance Limited distribution in 2020.
These decreases were partially offset by:
A $39 million increase due to SPP transmission services including the annual formula rate true-up.
A $37 million increase in employee-related expenses.
Asset Impairments and Other Related Charges decreased $93 million primarily due to a pretax expense recorded in 2019 related to previously retired coal-fired assets.
Depreciation and Amortization expenses increased $154 million primarily due to a higher depreciable base and increased depreciation rates approved at I&M, APCo and SWEPCo. This increase was partially offset in Retail Margins above.
Taxes Other Than Income Taxes increased $12 million primarily due to increased property taxes primarily at APCo, I&M, PSO and SWEPCo.
Other Income decreased $4 million primarily due to a decrease in affiliated interest income due to a decrease in interest rates in 2020.
Allowance for Equity Funds Used During Construction decreased $9 million primarily due to a decrease in the AFUDC base at I&M and the favorable impact of a FERC settlement agreement recorded in 2019.
Interest Expense decreased $3 million primarily due to the following:
A $10 million decrease primarily due to lower interest rates on long-term debt primarily at PSO and AEGCo.
A $6 million decrease primarily due to lower interest rates on variable rate loans and carrying charges recorded on various riders at I&M. This decrease was partially offset by a decrease in AFUDC base.
These decreases were partially offset by:
A $13 million increase primarily due to higher long-term debt balances at APCo.
Income Tax Expense increased $91 million primarily due to a decrease in amortization of Excess ADIT and an increase in pretax book income. The decrease in amortization of Excess ADIT not subject to normalization requirements is partially offset above in Gross Margin and Other Operation and Maintenance expenses.
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TRANSMISSION AND DISTRIBUTION UTILITIES

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(a)Other AEP Segments excludes Corporate and Other which is not considered a reportable segment.
Years Ended December 31,
Transmission and Distribution Utilities202020192018
(in millions)
Revenues$4,345.9 $4,482.5 $4,653.1 
Purchased Electricity682.7 794.3 858.3 
Amortization of Generation Deferrals— 65.3 223.9 
Gross Margin3,663.2 3,622.9 3,570.9 
Other Operation and Maintenance1,575.4 1,628.1 1,541.7 
Asset Impairments and Other Related Charges— 32.5 — 
Depreciation and Amortization751.1 789.5 734.1 
Taxes Other Than Income Taxes586.7 575.0 545.3 
Operating Income750.0 597.8 749.8 
Interest and Investment Income2.4 6.6 4.2 
Carrying Costs Income1.6 1.0 1.7 
Allowance for Equity Funds Used During Construction31.9 33.4 29.9 
Non-Service Cost Components of Net Periodic Benefit Cost29.4 30.3 32.3 
Interest Expense(289.2)(243.3)(248.1)
Income Before Income Tax Expense (Benefit)526.1 425.8 569.8 
Income Tax Expense (Benefit)29.7 (25.2)42.4 
Net Income496.4 451.0 527.4 
Net Income Attributable to Noncontrolling Interests— — — 
Earnings Attributable to AEP Common Shareholders$496.4 $451.0 $527.4 
87


Summary of KWh Energy Sales for Transmission and Distribution Utilities
Years Ended December 31,
202020192018
(in millions of KWhs)
Retail:
Residential26,518 26,407 27,042 
Commercial23,998 25,018 24,877 
Industrial22,432 23,289 23,908 
Miscellaneous749 779 760 
Total Retail (a)73,697 75,493 76,587 
Wholesale (b)1,859 2,335 2,441 
Total KWhs75,556 77,828 79,028 

(a)Represents energy delivered to distribution customers.
(b)Primarily Ohio’s contractually obligated purchases of OVEC power sold into PJM.

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88


Heating degree days and cooling degree days are metrics commonly used in the utility industry as a measure of the impact of weather on revenues.  In general, degree day changes in the eastern region have a larger effect on revenues than changes in the western region due to the relative size of the two regions and the number of customers within each region.
Summary of Heating and Cooling Degree Days for Transmission and Distribution Utilities
Years Ended December 31,
202020192018
(in degree days)
Eastern Region
Actual – Heating (a)2,743 3,071 3,357 
Normal – Heating (b)3,202 3,208 3,215 
Actual – Cooling (c)1,140 1,224 1,402 
Normal – Cooling (b)1,006 992 980 
Western Region
Actual – Heating (a)189 301 354 
Normal – Heating (b)313 322 325 
Actual – Cooling (d)2,846 2,989 2,861 
Normal – Cooling (b)2,711 2,699 2,688 

(a)Heating degree days are calculated on a 55 degree temperature base.
(b)Normal Heating/Cooling represents the thirty-year average of degree days.
(c)Eastern Region cooling degree days are calculated on a 65 degree temperature base.
(d)Western Region cooling degree days are calculated on a 70 degree temperature base.

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89


2020 Compared to 2019
 
Reconciliation of Year Ended December 31, 2019 to Year Ended December 31, 2020
Earnings Attributable to AEP Common Shareholders from Transmission and Distribution Utilities
(in millions)
Year Ended December 31, 2019$451.0 
Changes in Gross Margin:
Retail Margins90.4 
Margins from Off-system Sales(39.3)
Transmission Revenues44.2 
Other Revenues(55.0)
Total Change in Gross Margin40.3 
Changes in Expenses and Other:
Other Operation and Maintenance52.7 
Asset Impairments and Other Related Charges32.5 
Depreciation and Amortization38.4 
Taxes Other Than Income Taxes(11.7)
Interest and Investment Income(4.2)
Carrying Costs Income0.6 
Allowance for Equity Funds Used During Construction(1.5)
Non-Service Cost Components of Net Periodic Benefit Cost(0.9)
Interest Expense(45.9)
Total Change in Expenses and Other60.0 
Income Tax Expense(54.9)
Year Ended December 31, 2020$496.4 

The major components of the increase in Gross Margin, defined as revenues less the related direct cost of purchased electricity and amortization of generation deferrals were as follows:

Retail Margins increased $90 million primarily due to the following:
A $69 million net increase related to other various rider revenues in Ohio. This increase was partially offset in other expense items below.
A $61 million increase in rider revenues in Ohio associated with the DIR. This increase was partially offset in other expense items below.
A $30 million increase due to a provision for refund recorded in December 2019 as part of the 2019 Texas base rate case.
A $16 million increase from interim rate increases driven by increased distribution investment in Texas.
A $13 million increase due to new base rates implemented in June 2020 in Texas.
A $12 million increase from interim rate increases driven by increased transmission investment in Texas.
A $9 million increase in weather-normalized margins primarily in the residential class and partially offset in the industrial and commercial classes.
A $6 million increase in revenues associated with Ohio smart grid riders. This increase was partially offset in other expense items below.
A $5 million increase due to the change in the recording of merger savings as authorized by the PUCT in the most recent base rate case.
These increases were partially offset by:
A $58 million decrease due to a reversal of a regulatory provision in Ohio in the first quarter of 2019.
A $38 million decrease due to refunds in Texas of Excess ADIT and excess federal income taxes collected as a result of Tax Reform. This decrease was offset in Income Tax Expense below.
90


A $17 million net decrease in margin in Ohio for the Rate Stability Rider including associated amortizations which ended in the third quarter of 2019.
A $17 million decrease in weather-related usage in Texas primarily due to a 5% decrease in cooling degree days.
A $6 million decrease due to refunds to customers associated with the most recent base rate case in Texas. This decrease was offset in Other Revenues below.
Margins from Off-system Sales decreased $39 million primarily due to the following:
A $52 million decrease in Texas due to lower Oklaunion Power Station PPA revenues. This decrease was offset in Other Operation and Maintenance expenses below.
A $17 million decrease in sales in Ohio due to lower market prices and decreased sales volumes in 2020. This decrease was offset in Retail Margins above.
These decreases were partially offset by:
A $26 million increase in Ohio due to higher OVEC PPA deferrals. This increase was offset in Retail Margins above.
Transmission Revenues increased $44 million primarily due to the following:
A $48 million increase from interim rate increases driven by increased transmission investment in Texas.
A $16 million increase in Ohio due to the annual transmission formula rate true-up.
A $6 million increase due to additional investment in transmission assets in Ohio.
These increases were partially offset by:
A $14 million decrease in Texas due to a one-time credit to transmission customers as a result of Tax Reform and the most recent base rate case. This decrease was offset in Income Tax Expense below.
A $12 million decrease due to refunds to customers associated with the most recent base rate case in Texas. This decrease is offset in Other Revenues below.
Other Revenues decreased $55 million primarily due to the following:
A $96 million decrease in securitization revenue due to the AEP Texas Central Transition Funding II LLC bonds that matured in July 2020. This decrease was offset in Depreciation and Amortization expenses and Interest Expense below.
This decrease was partially offset by:
A $19 million increase in Ohio primarily due to third-party Legacy Generation Resource Rider revenue related to the recovery of OVEC costs. This increase was offset in Retail Margins above.
An $18 million increase in revenues due to the amortization of a provision for refund recorded in December 2019 as part of the most recent base rate case in Texas. This increase was offset in Retail Margins and Transmission Revenues above.

Expenses and Other and Income Tax Expense changed between years as follows:

Other Operation and Maintenance expenses decreased $53 million primarily due to the following:
A $67 million decrease due to prior year partial amortization of the AEP Texas Storm Restoration Securitization regulatory asset as a result of the AEP Texas Storm Cost Securitization financing order issued by the PUCT in June 2019. This decrease was offset in Income Tax Expense below.
An $18 million decrease in distribution expenses primarily due to vegetation management. This decrease was partially offset in Retail Margins above.
A $17 million decrease due to the revision of the Oklaunion Power Station ARO. This decrease was offset in Margins from Off-System Sales above.
A $16 million decrease in affiliated PPA expenses in Texas. This decrease was offset in Margins from Off-system Sales above.
A $12 million decrease due to a charitable contribution to the AEP Foundation in 2019.
A $7 million decrease in customer-related expenses.
A $5 million decrease due to a PUCO order to refund unused 2018 major storm reserve collections to customers. This decrease was offset in Retail Margins above.
These decreases were partially offset by:
A $62 million net increase in PJM transmission expenses, primarily due to a $94 million increase in recoverable expenses, partially offset by a $28 million decrease related to the annual transmission formula rate true-up. This increase was offset in Gross Margin above.
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A $19 million increase in remitted USF surcharge payments to the Ohio Department of Development to fund an energy assistance program for qualified Ohio customers. This increase was offset in Retail Margins above.
A $17 million increase in ERCOT transmission expenses. This increase was partially offset in Gross Margin above.
Asset Impairments and Other Related Charges decreased $33 million due to prior year regulatory disallowances in the 2019 Texas Base Rate Case.
Depreciation and Amortization expenses decreased $38 million primarily due to the following:
An $87 million decrease in securitization amortizations due to the AEP Texas Central Transition Funding II LLC bonds that matured in July 2020. This decrease was offset in Other Revenues above and Interest Expense below.
A $24 million decrease in amortizations associated with the Deferred Asset Phase-In-Recovery Rider in Ohio which ended in the second quarter of 2019. This decrease was offset in Retail Margins above.
These decreases were partially offset by:
A $31 million increase in depreciation expense due to an increase in the depreciable base of transmission and distribution assets.
A $22 million increase in Ohio recoverable DIR depreciation expense. This increase was partially offset in Retail Margins above.
An $11 million increase due to lower deferred equity amortizations associated with the Deferred Asset Phase-In-Recovery Rider in Ohio which ended in the second quarter of 2019.
A $6 million increase due to prior year under-recovery of revenues in Ohio associated with the Deferred Asset Phase-In-Recovery securitization which ended in the 2nd quarter of 2019. This decrease was offset in Retail Margins above.
Taxes Other Than Income Taxes increased $12 million primarily due to the following:
A $19 million increase in property taxes driven by additional investments in transmission and distribution assets and higher tax rates.
This increase was partially offset by:
A $6 million decrease in excise taxes due to lower demand in 2020 in Ohio. This decrease was offset in Retail Margins above.
Interest Expense increased $46 million primarily due to the following:
A $32 million increase due to higher long-term debt balances.
A $22 million increase due to the prior year deferral of previously recorded interest expense approved for recovery as a result of the Texas Storm Cost Securitization financing order issued by the PUCT in June 2019.
An $8 million increase due to due to a decrease in the debt component of AFUDC.
These increases were partially offset by:
An $8 million decrease in expense related to securitization assets. This decrease was offset above in Other Revenues and Depreciation and Amortization expenses.
A $6 million decrease due to lower short-term debt balances.
Income Tax Expense increased $55 million primarily due to an increase in pretax book income and a decrease in Excess ADIT not subject to normalization requirements as approved in the Texas Storm Cost Securitization financing order issued by the PUCT in 2019. The decrease in Excess ADIT not subject to normalization requirements was partially offset in Gross Margins and Other Operation and Maintenance Expenses above.
92


AEP TRANSMISSION HOLDCO

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(a)Other AEP Segments excludes Corporate and Other which is not considered a reportable segment.
Years Ended December 31,
AEP Transmission Holdco202020192018
(in millions)
Transmission Revenues$1,198.8 $1,073.2 $804.1 
Other Operation and Maintenance119.0 119.0 105.6 
Depreciation and Amortization257.6 183.4 137.8 
Taxes Other Than Income Taxes211.0 174.4 142.3 
Operating Income611.2 596.4 418.4 
Interest and Investment Income2.9 3.4 2.1 
Allowance for Equity Funds Used During Construction74.0 84.3 67.2 
Non-Service Cost Components of Net Periodic Benefit Cost2.0 2.7 2.6 
Interest Expense(133.2)(103.3)(90.7)
Income Before Income Tax Expense and Equity Earnings556.9 583.5 399.6 
Income Tax Expense130.8 136.2 95.3 
Equity Earnings of Unconsolidated Subsidiary82.4 72.8 68.7 
Net Income508.5 520.1 373.0 
Net Income Attributable to Noncontrolling Interests3.7 3.8 3.1 
Earnings Attributable to AEP Common Shareholders$504.8 $516.3 $369.9 
93


Summary of Investment in Transmission Assets for AEP Transmission Holdco
December 31,
202020192018
(in millions)
Plant in Service$10,327.5 $8,812.2 $7,008.4 
Construction Work in Progress1,499.7 1,521.8 1,651.1 
Accumulated Depreciation and Amortization595.7 418.9 282.8 
Total Transmission Property, Net$11,231.5 $9,915.1 $8,376.7 

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94


2020 Compared to 2019
 
Reconciliation of Year Ended December 31, 2019 to Year Ended December 31, 2020
Earnings Attributable to AEP Common Shareholders from AEP Transmission Holdco
(in millions)
Year Ended December 31, 2019$516.3 
Changes in Transmission Revenues:
Transmission Revenues125.6 
Total Change in Transmission Revenues125.6 
Changes in Expenses and Other:
Depreciation and Amortization(74.2)
Taxes Other Than Income Taxes(36.6)
Other Income(0.5)
Allowance for Equity Funds Used During Construction(10.3)
Non-Service Cost Components of Net Periodic Pension Cost(0.7)
Interest Expense(29.9)
Total Change in Expenses and Other(152.2)
Income Tax Expense5.4 
Equity Earnings of Unconsolidated Subsidiary9.6 
Net Income Attributable to Noncontrolling Interests0.1 
Year Ended December 31, 2020$504.8 

The major components of the increase in transmission revenues, which consists of wholesale sales to affiliates and nonaffiliates were as follows:

Transmission Revenues increased $126 million primarily due to the following:
A $208 million increase due to continued investment in transmission assets.
This increase was partially offset by the following:
A $65 million decrease as a result of the affiliated annual transmission formula rate true-up which is offset in Other Operation and Maintenance expense across affiliated load-serving entities.
A $17 million decrease as a result of the nonaffiliated annual transmission formula rate true-up.

Expenses and Other, Income Tax Expense and Equity Earnings of Unconsolidated Subsidiary changed between years as follows:

Depreciation and Amortization expenses increased $74 million primarily due to a higher depreciable base and an increase in depreciation rates as a result of regulatory orders in 2020 in Indiana, Virginia and Michigan.
Taxes Other Than Income Taxes increased $37 million primarily due to higher property taxes as a result of increased transmission investment.
Allowance for Equity Funds Used During Construction decreased $10 million primarily due to the following:
A $13 million decrease due to lower CWIP.
A $12 million decrease driven by the favorable impact of a FERC settlement agreement recorded in 2019.
These decreases were partially offset by:
A $13 million increase driven by FERC audit findings recorded in 2019.
Interest Expense increased $30 million primarily due to higher long-term debt balances.
Income Tax Expense decreased $5 million primarily due to lower pretax book income and an increase in amortization of Excess ADIT.
Equity Earnings of Unconsolidated Subsidiary increased $10 million primarily due to higher pretax equity earnings at PATH-WV and ETT.
95


GENERATION & MARKETING

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(a)Other AEP Segments excludes Corporate and Other which is not considered a reportable segment.
Years Ended December 31,
Generation & Marketing202020192018
(in millions)
Revenues$1,725.6 $1,857.6 $1,940.3 
Fuel, Purchased Electricity and Other1,403.6 1,456.2 1,537.3 
Gross Margin322.0 401.4 403.0 
Other Operation and Maintenance124.9 223.8 229.3 
Asset Impairments and Other Related Charges— 31.0 47.7 
Depreciation and Amortization72.8 69.5 41.0 
Taxes Other Than Income Taxes13.2 15.6 13.4 
Operating Income111.1 61.5 71.6 
Interest and Investment Income3.2 7.7 13.1 
Non-Service Cost Components of Net Periodic Benefit Cost15.4 14.9 15.2 
Interest Expense(24.0)(30.0)(14.9)
Income Before Income Tax Benefit and Equity Earnings (Loss)105.7 54.1 85.0 
Income Tax Benefit(108.0)(53.8)(49.2)
Equity Earnings (Loss) of Unconsolidated Subsidiaries3.2 (3.8)0.5 
Net Income216.9 104.1 134.7 
Net Loss Attributable to Noncontrolling Interests(10.0)(8.7)(0.6)
Earnings Attributable to AEP Common Shareholders$226.9 $112.8 $135.3 
96


Summary of MWhs Generated for Generation & Marketing
Years Ended December 31,
202020192018
(in millions of MWhs)
Fuel Type:
Coal
Renewables
Total MWhs

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97


2020 Compared to 2019
 
Reconciliation of Year Ended December 31, 2019 to Year Ended December 31, 2020
Earnings Attributable to AEP Common Shareholders from Generation & Marketing
(in millions)
Year Ended December 31, 2019$112.8 
Changes in Gross Margin:
Merchant Generation(78.2)
Renewable Generation9.7 
Retail, Trading and Marketing(10.9)
Total Change in Gross Margin(79.4)
Changes in Expenses and Other:
Other Operation and Maintenance98.9 
Asset Impairments and Other Related Charges31.0 
Depreciation and Amortization(3.3)
Taxes Other Than Income Taxes2.4 
Interest and Investment Income(4.5)
Non-Service Cost Components of Net Periodic Benefit Cost0.5 
Interest Expense6.0 
Total Change in Expenses and Other131.0 
Income Tax Benefit54.2 
Equity Earnings of Unconsolidated Subsidiaries7.0 
Net Loss Attributable to Noncontrolling Interests1.3 
Year Ended December 31, 2020$226.9 

The major components of the decrease in Gross Margin, defined as revenues less the related direct cost of fuel, including consumption of chemicals and emissions allowances, purchased electricity and certain cost-of-service for retail operations were as follows:

Merchant Generation decreased $78 million primarily due to the reduction of capacity revenues and energy margins in 2020 and the retirement of the Conesville Plant, Units 5 and 6 in 2019, Unit 4 in 2020 and the Oklaunion Power Station in 2020.
Renewable Generation increased $10 million primarily due to the Sempra Renewables LLC acquisition and other renewable projects placed in-service.
Retail, Trading and Marketing decreased $11 million primarily due to lower retail margins.

Expenses and Other, Income Tax Benefit and Equity Earnings of Unconsolidated Subsidiaries changed between years as follows:

Other Operation and Maintenance expenses decreased $99 million primarily due to following:
A $36 million decrease due to the retirements of Conesville Plant Units 5 and 6 in 2019 and Unit 4 in 2020.
A $34 million decrease due to a gain recorded on the sale of land.
An $18 million decrease related to the Oklaunion PPA with AEP Texas primarily due to an ARO revision.
An $11 million decrease primarily in employee expenses due to the sale of the Stuart Plant in 2019.
Asset Impairments and Other Related Charges decreased $31 million primarily due to impairment charges related to the Conesville Plant in 2019.
Depreciation and Amortization expenses increased $3 million primarily due to a higher depreciable base from increased investments in renewable energy sources.
98


Interest and Investment Income decreased $5 million due to lower returns on investments.
Interest Expense decreased $6 million primarily due lower borrowing costs in 2020.
Income Tax Benefit increased $54 million primarily due to the realization of tax benefit related to the 5-year NOL carryback provision of the CARES Act and an increase in PTCs. This decrease was partially offset by an increase in pretax book income.
Equity Earnings of Unconsolidated Subsidiaries increased $7 million primarily due to the Sempra Renewables LLC acquisition.

99


CORPORATE AND OTHER

2020 Compared to 2019

Earnings attributable to AEP Common Shareholders from Corporate and Other increased from a loss of $141 million in 2019 to a loss of $90 million in 2020 primarily due to:

A $32 million decrease in tax expense primarily due to the following:
A $21 million decrease in state income tax expense related to unitary state filing requirements.
A $5 million decrease in permanent tax expense.
A $3 million decrease due to a favorable true-up related to the 2019 federal income tax return.
A $2 million decrease due to the realization of tax benefit related to the 5-year NOL carryback provision of the CARES Act.
A $32 million gain on the valuation of common share warrants for an interest in a privately held investee.
A $5 million write-off of an equity investment and related assets in 2019.

These items were partially offset by:

A $12 million decrease in interest income from affiliates.
A $7 million increase in general corporate expenses.

AEP SYSTEM INCOME TAXES

2020 Compared to 2019

Income Tax Expense increased $53 million primarily due to a decrease in amortization of Excess ADIT and an increase in pretax book income. This increase is partially offset by the recognition of tax benefit related to the 5-year NOL carryback provision as a result of the CARES Act, an increase in PTCs and a decrease in state tax expense.
100


FINANCIAL CONDITION

AEP measures financial condition by the strength of its balance sheet and the liquidity provided by its cash flows.

LIQUIDITY AND CAPITAL RESOURCES

Debt and Equity Capitalization
December 31,
20202019
(dollars in millions)
Long-term Debt, including amounts due within one year$31,072.5 57.2 %$26,725.5 54.1 %
Short-term Debt2,479.3 4.6 2,838.3 5.7 
Total Debt33,551.8 61.8 29,563.8 59.8 
AEP Common Equity20,550.9 37.8 19,632.2 39.6 
Noncontrolling Interests223.6 0.4 281.0 0.6 
Total Debt and Equity Capitalization$54,326.3 100.0 %$49,477.0 100.0 %

AEP’s ratio of debt-to-total capital increased from 59.8% to 61.8% as of December 31, 2019 and 2020, respectively, primarily due to an increase in debt to support distribution, transmission and renewable investment growth.

Liquidity

Liquidity, or access to cash, is an important factor in determining AEP’s financial stability.  Management believes AEP has adequate liquidity under its existing credit facilities. As of December 31, 2020, AEP had a $4 billion revolving credit facility to support its commercial paper program.  Additional liquidity is available from cash from operations and a receivables securitization agreement.  Management is committed to maintaining adequate liquidity.  AEP generally uses short-term borrowings to fund working capital needs, property acquisitions and construction until long-term funding is arranged.  Sources of long-term funding include issuance of long-term debt, leasing agreements, hybrid securities or common stock. There was increased volatility in the capital markets during the first quarter of 2020 resulting in higher commercial paper cost and limited access. To address these issues and the uncertainty around COVID-19, in March 2020, AEP entered into a $1 billion 364-day Term Loan and borrowed the full amount. In November 2020, AEP repaid the 364-day Term Loan.

Net Available Liquidity

AEP manages liquidity by maintaining adequate external financing commitments.  As of December 31, 2020, available liquidity was approximately $2.5 billion as illustrated in the table below:
AmountMaturity
(in millions)
Commercial Paper Backup:
Revolving Credit Facility$4,000.0 June 2022
Cash and Cash Equivalents392.7 
Total Liquidity Sources4,392.7 
Less: AEP Commercial Paper Outstanding1,852.3 
Net Available Liquidity$2,540.4 

AEP uses its commercial paper program to meet the short-term borrowing needs of its subsidiaries.  The program funds a Utility Money Pool, which funds AEP’s utility subsidiaries; a Nonutility Money Pool, which funds certain AEP nonutility subsidiaries; and the short-term debt requirements of subsidiaries that are not participating in either money pool for regulatory or operational reasons, as direct borrowers.  The maximum amount of commercial paper outstanding during 2020 was $3 billion.  The weighted-average interest rate for AEP’s commercial paper during 2020 was 1.28%.


101


Other Credit Facilities

An uncommitted facility gives the issuer of the facility the right to accept or decline each request made under the facility. AEP issues letters of credit on behalf of subsidiaries under six uncommitted facilities totaling $405 million.  The Registrants’ maximum future payments for letters of credit issued under the uncommitted facilities as of December 31, 2020, was $180 million with maturities ranging from January 2021 to December 2021.

Financing Plan

As of December 31, 2020, AEP had $2.1 billion of long-term debt due within one year. This included $235 million of Pollution Control Bonds with mandatory tender dates and credit support for variable interest rates that requires the debt be classified as current and $190 million of securitization bonds and DCC Fuel notes.  Management plans to refinance the majority of the maturities due within one year on a long-term basis.

Securitized Accounts Receivables

AEP receivables securitization agreement provides a commitment of $750 million from bank conduits to purchase receivables and expires in September 2022.

In May 2020, AEP Credit amended its receivables securitization agreement to increase the eligibility criteria related to aged receivable requirements for the participating affiliated utility subsidiaries in response to the COVID-19 pandemic. As of December 31, 2020, the affiliated utility subsidiaries are in compliance with all requirements under the agreement. To the extent that an affiliated utility subsidiary is deemed ineligible under the agreement, the affiliated utility subsidiary would no longer participate in the receivables securitization agreement and the Registrants would need to rely on additional sources of funding for operation and working capital, which may adversely impact liquidity. The receivables that are ineligible under the receivables securitization agreement are financed with short-term debt at AEP Credit.

Debt Covenants and Borrowing Limitations

AEP’s credit agreements contain certain covenants and require it to maintain a percentage of debt-to-total capitalization at a level that does not exceed 67.5%.  The method for calculating outstanding debt and capitalization is contractually-defined in AEP’s credit agreements.  Debt as defined in the revolving credit agreement excludes securitization bonds and debt of AEP Credit. As of December 31, 2020, this contractually-defined percentage was 58.6%. Non-performance under these covenants could result in an event of default under these credit agreements.  In addition, the acceleration of AEP’s payment obligations, or the obligations of certain of AEP’s major subsidiaries, prior to maturity under any other agreement or instrument relating to debt outstanding in excess of $50 million, would cause an event of default under these credit agreements.  This condition also applies in a majority of AEP’s non-exchange-traded commodity contracts and would similarly allow lenders and counterparties to declare the outstanding amounts payable.  However, a default under AEP’s non-exchange-traded commodity contracts would not cause an event of default under